Summer Training Report
On
“POWER MARKET TREND ANALYSIS AND
OPEN ACCESS POWER SALES MECHANISM
(LTOA, MTOA, STOA)”
UNDER THE GUIDLIANCE OF
Mrs. RACHNA VATS, Sr. Fellow, NPTI, Faridabad
&
Mr. SUMANTA CHAND, Associate Manager, Sterlite Energy Limited
At
STERLITE ENERGY LIMITED
(SUBSIDIARY OF VEDANTA RESOURCES)
Submitted By
SANJAY KUMAR MAHATO
Roll no. 76
Batch 11th (2012-14)
MBA in Power Management
Affiliated to
certificate
Page | 2
Acknowledgement
I am having great pleasure to present this report titled “POWER MARKET TREND
ANALYSIS AND OPEN ACCESS POWER SALES MECHANISM (LTOA, MTOA,
STOA)”. I take this opportunity to express my sincere thanks and gratitude to all who
contributed to make this a success.
I would also like to acknowledge Mr. A. K. GOYAL , Plant Head (Sterlite Energy ltd,
Jharsuguda) for his valuable support and guidance throughout this project.
I would also like to thank Mr. SUMANTA CHAND, Associate Manager who imparted me
with their valuable guidance during the internship period.
Special thanks go to all the staff members of STERLITE ENERGY LTD Without their
insights and helpful thoughts, I would not have gained as much information as I have. Their help
has sparked my interest even more! Thanks!
I wish to express my deep sense of gratitude to my Internal Guide, Mrs. Rachna Vats
(Sr. fellow) , NPTI for her able guidance and useful suggestions, which helped me in completing
the project work, in time. I also, thank Mr. S.K. Chaudhary, Principal Director (CAMPS),
NPTI, Mrs. Manju Mam, Director (MBA), NPTI, Mrs. Indu Maheshwari (Dy.Director) ,
Miss Farida Khan, Asst. Director and NPTI for providing constant support and assistance
whenever required.
Finally, yet importantly, I would like to express my heartfelt thanks to my beloved parents for
their blessings, my friends/classmates for their help and wishes for the successful completion of
this project.
Page | iii
DECLARATION
I, SANJAY KUMAR MAHATO, Roll No. 76 student of III semester M.B.A (Power
Management, 2012-2014 of the National Power Training Institute, Faridabad hereby
declare that the Summer Training Report entitled “POWER MARKET TREND
ANALYSIS AND OPEN ACCESS POWER SALES MECHANISM (LTOA,
MTOA, STOA)” is an original work and the same has not been submitted to any other
Institute for the award of any other degree.
A Seminar presentation of the Training Report was made on ______________ and the
suggestions as approved by the faculty were duly incorporated.
Date:
Place: Faridabad, Haryana
Presentation In charge
Signature of the
(Faculty)
Candidate
Countersigned
Director/Principal of the Institute
Page | iv
EXECUTIVE SUMMARY
Power trading in India accounts for 9% of the net generation. Trading basically involves
unscheduled exchange, bilateral trading and trading through power exchange. Unscheduled
exchange accounts for around 40-45% of the total power traded, followed by 40-43% bilateral
trade and rest through power exchanges. The proportion of unscheduled power exchange is
expected to decline in coming years due to Power Ministry continuous effort to maintain grid
discipline. In bilateral trade there are sub-sections like short term trading, medium and long term
trading and cross border trading. Power Trading, as defined by EA- 2003, is the purchase of
electricity for resale thereof.
This Report comprises of an effort to study and analyze the Indian power market scenario and
also power market size and structure. In this report I have studied and analyze the past and recent
capacity addition of power, region wise demand and availability of power which help to
determine the power deficit region.
I have also collected and analyzed short term power trading data for past five months which help
to identify the major firm in the market holding the largest share in volume of power transacted
in the short term trading segment which enables a firm to make its long and short term strategy in
power sales.
Through the study I able to know quantity of power that was being traded in different regions of
India and also the rate and trading margin gained from the transaction.
During the study we also analyze the corridor analysis of long term open access and medium
term open access which enable to know the key purchaser of power and also Private project
commissioned or in progress in 2013-14.
Page | v
LIST OF TABLES
TABLE NO.
Table no. 1
Table no.2
Table no.3
Table no.4
Table no.5
Table no.6
Table no.7
Table no.8
Table no.9
Table no.10
Table no.11
Table no.12
Table no.13
Table no.14
CONTENT
PLANT LOAD FACTOR
PER-CAPITA CONSUMPTION OF ELECTRICITY
AT & C LOSSES
DETAILS OF JHARSUGUDA IPP:GROWTH RATE OF INSTALLED CAPACITY
RESOURCES WISE IN FY 2012-13
COAL BASED THERMAL POWER GENERATION
ADDITION BY PRIVATE SECTOR IN 2013-14
SECTOR WISE GROWTH IN POWER SECTOR IN 2012-13
LOAD GENERATION BALANCE REPORT 2013-2014
LIST OF INTER-STATE TRADING LICENSEES
PRICE OF ELECTRICITY TRANSACTED THROUGH
TRADERS (TIME-WISE), APRIL 2013
PRICE OF ELECTRICITY TRANSACTED THROUGH
POWER EXCHANGE,APRIL 2013
VOLUME AND PRICE OF ELECTRICITY IN TERM
AHEAD MARKET OF PXIL, APRIL 2013
PRICE OF ELECTRICITY TRANSACTED THROUGH UI,
APRIL 2013
LIST OF INTER-STATE TRADING LICENSEES
PAGE
NO.
2
3
3
10
18
20
21
23
28
28
29
29
29
31
Page | vi
LIST OF FIGURES
FIG. NO.
FIG. NO. 1
CONTENTS
PAGE
NO.
GROWTH RATE OF INSTALLED CAPACITY RESOURCES
19
WISE IN FY 2012-13
FIG.NO.2
COAL BASED THERMAL POWER GENERATION
ADDITION BY PRIVATE SECTOR IN 2013-14
20
FIG. NO.3
SECTOR WISE GROWTH IN POWER SECTOR IN 2012-13
22
FIG.NO.4
FIG. NO.5
FIG. NO.6
REGION WISE INSTALLED CAPACITY
22
24
24
FIG. NO.7
FIG.NO.8
FIG. NO.9
FIG. NO.10
FIG. NO.11
FIG. NO.12
FIG. NO.13
FIG. NO.14
FIG. NO.15
FIG. NO.16
FIG. NO.17
FIG. NO.18
FIG. NO.19
FIG. NO.20
FIG. NO.21
FIG. NO.22
ANTICIPATED MONTH WISE POWER SUPPLY POSITION
OF INDIA DURING THE YEAR 2013-14
REGION WISE REQUIREMENT AND AVAILABILITY
COMPARISON
REQUIREMENT OF ELECTRICITY IN REGION WISE:AVAILABILITY OF ELECTRICITY IN REGION WISE
SURPLUS/DEFICIT OF ELECTRICITY REGION WISE:VOLUME OF SHORT-TERM TRANSACTIONS OF
ELECTRICITY IN INDIA, APRIL-2013
TOP FOUR POWER PURCHASING STATES
VOLUME OF PRICE PURCHASED AND WEIGHTED
AVERAGE PURCHASE PRICE IN INR/KWH OFFER BY
THE STATE.
ELECTRICITY PURCHASED BY TOP 4 STATES
QUANTITY OF POWER PURCHASED AND PRICE OFFER
INR/KWH
VOLUME OF POWER PURCHASED BY TOP 5 STATES
THROUGH NETS
VOLUME OF POWER PURCHASED AND WEIGHTED
AVERAGE PURCHASE PRICE IN INR/KWH OFFER BY
THE STATE:VOLUME OF ELECTRICICTY PURCHASED BY PTC
VOLUME OF POWER PURCHASED AND WEIGHTED
AVERAGE PURCHASE PRICE IN INR/KWH OFFER BY
THE STATE BY PTC
WEIGHTED AVG.PURCHASE PRICE AT TRADING
LICENCEES
INDIAN ENERGY EXCHANGE PRICE ANALYSIS REGION
WISE:INDIAN ENERGY EXCHANGE PRICE ANALYSIS REGION
25
26
27
27
28
33
34
35
35
36
37
37
38
38
44
45
Page | vii
WISE LAST 5 YEAR
FIG. NO.23
REGION WISE VOLUME OF ELECTRICITY SOLD BY
IEX(2008-13)
TRANSFER OF ELECTRICITY REGION WISE THROUGH
MEDIUM TERM OPEN ACCESS
46
FIG. NO.25
SHORT TERM TRANSACTION OF ELECTRICITY FOR THE
YEAR 2012-13 IN QUARTERLY BASIS
68
FIG. NO.26
VOLUME OF IMPORT THROUGH UI CHARGES OF FIVE
STATES
71
FIG. NO.24
63
Page | viii
TABLE OF CONTENTS
SL.No TOPIC
PAGE
CERTIFICATE
ii
ACKNOWLEDGEMENT
iii
DECLARATION
iv
EXECUTIVE SUMMARY
v
LIST OF TABLES
vi
LIST OF FIGURES
vii
CHAPTER 1:INTRODUCTION
1.1
INTRODUCTION
1
1.1.1
HISTORY OF INDIAN POWER SECTOR
1
1.1.2
BRIEF INTRODUCTION TO INDIAN ELECTRICITY SECTOR
2
1.2
1.3
OBJECTIVE OF THE PROJECT
3
SCOPE OF THE PROJECT
4
1.4
ABOUT THE ORGANIZATION
5
1.5
JHARSUGUDA POWER PROJECT
8
1.6
PROBLEM STATEMENT
11
CHAPTER 2:LITERATURE REVIEW, POWER TRADING AND INDIAN
ENERGY EXCHANGE
2.1
LITERATURE REVIEW
12
2.2
POLICY REVIEW
15
2.3
INDIAN POWER MARKET
18
2.4
STRUCTURE OF INDIAN POWER MARKET
19
2.5
INDIAN POWER TRADING MARKET
30
2.5.1
TATA POWER TRADING ANALYSIS
33
2.5.2
NVVN ANALYSIS
34
Page | ix
2.5.3
NETS ANALYSIS
36
2.5.4
PTC ANALYSIS
37
2.6
INDIAN ENERGY EXCHANGE
39
2.6.1
DAY AHEAD MARKET
39
2.6.2
TERM AHED MARKET
41
2.6.3
2.6.4
INDIAN ENERGY EXCHANGE PRICE ANALYSIS
44
INDIAN ENERGY EXCHANGE VOLUME ANALYSIS
44
CHAPTER -3:LTOA, MTOA, STOA, UI, CORRIDOR ANALYSIS
3.1
LONG TERM OPEN ACCESS
47
3.2
MEDIUM TERM OPEN ACCESS
56
3.3
SHORT TERM OPEN ACCESS
63
3.4
UNSCHEDULE INTERCHANGE
60
3.5
CORRIDOR ANALYSIS
71
CHAPTER 4: RESULTS , CONCLUSIONS AND RECOMMENDATIONS
4.1
CONCLUSION
78
4.2
RECOMMENDATIONS
79
4.3
BIBLIOGRAPHY
81
Page | x
CHAPTER 1: INTRODUCTION
1.1 INTRODUCTION
1.1.1 HISTORY OF INDIAN POWER SECTOR
The first demonstration of electric light in Calcutta was conducted on 24 July, 1879 by P W
Fleury & Co. Mumbai saw electric lighting for the first time in 1882 at Crawford Market. First
hydro-electric installation in India was setup by Crompton & Co for the Darjeeling Municipality
in 1896. The Bombay Electric Supply & Tramways Company (B.E.S.T.) set up a generating
station in 1905 to provide electricity for the tramway. In November, 1931, electrification of the
meter gauge track between Madras Beach and Tambaram was started.
The Indian Electricity Act 1910-: It provided the underpinnings for the structure of power
industry. The production and distribution of power was allowed through licenses granted by the
state government. Provisions were made for laying down of wires, and the relationship between
the power generator and consumers was defined.
The Electricity (supply) Act, 1948-: It allowed the creation of State Electricity Boards (SEBs).
The SEBs was responsible for the generation, transmission and distribution of power within the
state periphery. Central Electricity Authority (CEA) was established to oversee the planning and
development of power sector and guide SEBs.
In 1975, amendments were made to enable central government to set up and maintain power
plants. Thus was formed the National Thermal Power Corporation (NTPC) which is the biggest
power generation company in India till date. Private sector investment was opened for power
generation sector as late as in 1991.
In 1998 transmission of power was opened for private investment and regulatory commissions
were set up at Central and State level to frame the policies and ensure their implementation in
their areas of jurisdiction. Central regulatory commissions were established for inter-state
matters and state commissions for intra-state matters.
Page | 1
The Electricity Act 2003-: Repealed all previous acts and brought a paradigm shift in Indian
power market. No license was required for setting up generation capacity. Distribution was made
license free for notified rural areas. Development of power market was envisioned. Trading of
electricity was recognised as a distinct activity. Open access was granted for bulk producers and
consumers. It was amended further in 2007 to bring in modifications. The prominent ones are
regarding subsidy and combined responsibility of state and central regulators. Power sector
reforms are being pursued since then and continue till date.
1.1.2 BRIEF INTRODUCTION TO INDIAN ELECTRICITY SECTOR
The electricity sector in India had an installed capacity of 225.133 Gigawatt (GW) as of May
2013, the world's fifth largest. Captive power plants generate an additional 34.44 GW. Thermal
power plants constitute 68% of the installed capacity, hydroelectric about 17.6 % and rest being
a combination of wind, small hydro, biomass, waste-to-electricity, and nuclear. India set a target
of generating 975000 MU electricity for 2013-14 in which 161813..05 MU has been achieved up
to may-13.
In terms of fuel, coal-fired plants account for 58.5 % of India's installed electricity capacity,
compared to South Africa's 92%; China's 77%; and Australia's 76%.In December 2011, over 300
million Indian citizens had no access to electricity. Over one third of India's rural population
lacked electricity, as did 6% of the urban population of those who did have access to electricity
in India; the supply was intermittent and unreliable.
Table 1: Plant load Factor All India Thermal PLF (%)
2005-06
2006-07
2007-08
2008-09
2009-10
2010-11
2011-12
2012-13
2013-14(up to may)
73.6
76.8
78.6
77.2
77.5
75.07
73.32
70.76
70.76
There was increase in Plant load factor since 2005-06 onwards till 2009-10 and then there was
regular decrease in plant load factor and in 2013-14 plant load factor is 70.76.The major reason
for low plant load factor is unavailability of fuel i.e. coal and also in some cases there is
Page | 2
transmission constraints as NEW grid has limited TTC(Total transmission capacity) to Southern
grid and generating station located in NEW grid region not able to sell their power to southern
grid this led their unit remains idle.
Table 2: Per-Capita consumption of electricityAll India Annual per Capita consumption of Electricity
Year
Per Capita Consumption (
kWh)
2005-06
2006-07
2007-08
2008-09
2009-10
2010-11
2011-12
631.4
671.9
717.1
733.5
778.6
818.8
879.22*
Per-capita consumption of Electricity in 2011-12 is 879.22kWh. , in contrast to the world wide
per capita annual average of 2600 kWh and 6200 kWh in the European Union. Temperature
difference could be the reason for consumption of electricity as these European countries are
colder and they require more heating equipments which consumes more unit of electricity.
Table 3 :AT & C LossesAT&C losses (in %)
2004-05
2005-06
2006-07
2007-08
2008-09
2009-10
2010-11
34.33
33.02
30.62
29.45
27.37
26.58
26.15
India is gradually improving in aggregate technical and commercial loss. In 2004-05 India‘s
AT&C loss was 34.33% and in 2010-11 it improves to 26.15% it is still very high and
government is taking initiatives like R-APDRP (Restructured accelerated power development
and reform program) to improve it to below 12%.
India currently suffers from a major shortage of electricity generation capacity, even though it is
the world's fourth largest energy consumer after United States, China and Russia. The
International Energy Agency estimates India needs an investment of at least $135 billion to
provide universal access of electricity to its population. The International Energy Agency
estimates India will add between 600 GW to 1200 GW of additional new power generation
Page | 3
capacity before 2050. This added new capacity is equivalent to the 740 GW of total power
generation capacity of European Union (EU-27) in 2005. The technologies and fuel sources India
adopts, as it adds this electricity generation capacity, may make significant impact to global
resource usage and environmental issues.
1.2 Objective and Scope of the Project
1.2.1 Objective of the project
The main objectives of the projects are-:
1. To study and analyze the past and present total installed capacity of power of India.
Contribution of centre, state and private sector in it and also resource wise contribution of
power.
2. To study and analyze region wise demand and availability of Electricity to determine
peak shortage and total energy deficit.
3. To study and analyze the power market size and structure.
4. To identify the need and importance of an efficient short term power market.
5. To analyse Volume and Price of short term Power market
6. Benchmarking of Trading Licensee
7. To understand the development process of various developed power market and identify
various successful market tools that can be implemented in India.
8. To identify states for investment opportunities through analysis of different market
parameters influencing the power market.
9. To understand the various risk associated with Short term power market for various
stakeholders.
1.3 Scope of the project
Under the scope of the project it covers the participating entities in short term market and the
CERC regulation for the same.
The participating entities in short term market are-:
Page | 4
1. The various regulatory authorities.
2. Power exchanges.
3. Trading licensee.
4. Merchant generators
5. And states discoms.
1.4 About the Organisation
Vedanta Group/Vedanta Resources:Vedanta Resources plc is a global diversified metals and mining company headquartered in
London, United Kingdom. It is the largest mining and non-ferrous metals company in India and
also has mining operations in Australia and Zambia. Its main products are copper, zinc,
aluminium, lead and iron ore.
History:-The Company was founded by Anil Agarwal in Mumbai in 1976. It was first listed on
the London Stock Exchange in 2003 when it raised $876 million through an Initial Public
Offering. Meanwhile in 2006 it acquired Sterlite Gold, a gold mining business. It raised an
additional $2bn through an ADR issue in 2007.In 2008 it bought certain of the assets of Asarco,
a copper mining business, out of Chapter 11 for $2.6bn. In December 2011 it also completed the
US$8.67 billion acquisition of Cairn's Indian unit heralding its foray in the oil sector.
The Company has experienced significant growth in recent years through various expansion
projects for our copper, zinc, lead silver, aluminium, iron power and power businesses. Group
Revenue for the fiscal year ending 31 March 2011 was US$ 11.4 billion.
Vedanta has spent approximately two-third of our US$ 19 billion capital expenditure programme
as of 30 September 2011.Vedanta is the world‘s largest integrated Zinc Lead producer and
among the top producers of copper, iron ore and silver.
Operations:-
Page | 5
Area
Subsidiaries
Copper
Sterlite Industries (India) Ltd.: Sterlite is registered office headquartered in
Tuticorin, India. Sterlite has been a public listed company in India since 1988, and
its equity shares are listed and traded on the NSE and the BSE, and are also listed
and traded on the NYSE in the form of ADSs. Vedanta owns 53.9% of Sterlite and
have management control of the company.
Konkola Copper Mines: Vedanta own 79.4% of KCM‘s share capital and have
management control of the company. KCM‘s other shareholder is ZCCM
Investment Holdings Plc. The Government of Zambia has a controlling stake in
ZCCM Investment Holdings Plc.
Copper Mines of Tasmania Pty Ltd.: CMT is headquartered in Queenstown,
Tasmania. Sterlite owns 100.0% of CMT and has management control of the
company.
Zinc
Hindustan Zinc Limited: HZL is headquartered in Udaipur in the State of
Rajasthan. HZL‘s equity shares are listed and traded on the NSE and BSE. Sterlite
owns 64.9% of the share capital in HZL and has management control. Sterlite has a
call option to acquire the Government of India‘s remaining ownership interest.
Aluminium
Bharat Aluminium Company Ltd.: BALCO is headquartered at Korba in the
State of Chhattisgarh. Sterlite owns 51.0% of the share capital of BALCO and has
management control of the company. The Government of India owns the
remaining 49.0%. Sterlite exercised an option to acquire the Government of India‘s
remaining ownership interest in BALCO in March 2004.
Vedanta Aluminium Ltd.: Vedanta Aluminium is headquartered in Jharsuguda,
State of Orissa. Vedanta owns 70.5% of the share capital of Vedanta Aluminium
and Sterlite owns the remaining 29.5% share capital of Vedanta Aluminium.
Vedanta Aluminium produces ingots, billets & wire rods that are sold in the
markets around the World. Vedanta Aluminium Limited (VAL) has acquired
24.5% stake in L & T subsidiary RaykalAluminium. Based on achieving certain
milestones, VAL will fully acquire RaykalAluminium in phases.
Page | 6
Madras Aluminium Company Ltd.: MALCO is headquartered in Mettur, India.
MALCO‘s equity shares are listed and traded on the NSE and BSE. They own
93.9% of MALCO‘s share capital and have management control of the company.
Sesa Goa Limited: Sesa Goa is headquartered in Panaji, India, and its equity
Iron ore
shares are listed and traded on the NSE and BSE. Vedanta owns 57.1% of Sesa and
has management control of the company.
Commercial
power
generation
business
Sterlite Energy Limited: Sterlite Energy is headquartered in Mumbai.
Sterlite owns 100.0% of Sterlite Energy and has management control of the
company.
Group Structure & Business Summary:-
Page | 7
About Sterlite Energy Ltd.:Sterlite Energy Limited (SEL) is a part of Vedanta Resources plc , a London listed FTSE 100
diversified metals and mining major with Aluminium, Copper, Zinc and Iron ore operations in
India, Australia and Zambia, and a subsidiary of Vedanta group flagship company, Sterlite
Industries (India) Limited. SEL was established to develop, construct and operate power plants
and seeks to become one of India‘s leading commercial power generation companies.
Value System at Sterlite:-
Values
Sterlite believe in fostering an entrepreneurial spirit throughout their
Entrepreneurship
businesses and value the ability to foresee business opportunities early
in the cycle and act on them swiftly.
Sterlite believe to deliver industry-leading growth and generate
Growth
significant
value
for
shareholders.
Achieving excellence in all that we do is our way of life. Sterlite
Excellence
consistently deliver projects ahead of time at industry-leading costs of
construction and within budget.
Sterlite recognise that they must responsibly deliver on the promises we
Trust
make to earn that trust. They constantly strive to meet stakeholder
expectations and deliver ahead of expectations.
Sustainability
Sterlite believe that the principle of sustainability is a key component of
conducting business in a responsible manner and it is a primary aim of
Vedanta to operate as a good corporate citizen.
Page | 8
What Sterlite Logo Says!! :-
The Logo Unit represents the energy flow from a source. Sterlite has used ‗Energy
Waves‘ in an artistic way as elements in the logo units to depict energy (power). The tall
and bold typeface in the logo represents the ―ambition, scale and stability‖ of the
company.
The logo has drawn inspiration from the Indian ‗tri-colour‘ Flag - the two major colours
‗saffron & green‘ - a logo that can connect to the national sentiment, a logo that can be
easily
recognized
by
commoners,
a
logo
that
oozes
energy.
Colours Blue & Orange of the logo carries the values of the Vedanta group company.
The colours Orange connote energy generation & Green represents the environment
friendly
approach.
1.5 Sterlite Projects:1-Jharsuguda Project: -Sterlite Energy Ltd has taken a major initiative towards the advancement
of the power infrastructure in Orissa through its 4 x 600 MW coal-based independent power
plant (IPP) in Jharsuguda district. The IPP project envisages a total capital outlay of Rs. 8,200
crores. The power plant entails a number of pioneering achievements in the Indian power sector.
One of the largest coal handling plants to handle 44,000 MT of coal per day, which is equivalent
to 14 rakes of coal a day and a power generation capacity to produce 57 million units/day. In
addition to this, a Hybrid ESP with fabric filter is being deployed for the first time in an Indian
power plant. The plant also has a dual LP-flow steam turbine and four 160 meters high natural
draft cooling towers. Other important features of the plant include two 275 meters high multi-
Page | 9
flue stacks and a high concentration slurry disposal (HCSD) system for dry ash and highly
concentrated slurry. The company has made extensive arrangements to source raw materials for
the power plant. The Hirakud Reservoir is being used as a water source and coal- the chief raw
material, is being derived from the IB Valley coalfield. Power would be supplied to consumers
through the high-voltage power lines.
As a prime advocate of sustainable development, Sterlite Energy Ltd. Puts a premium on
environmentally friendly construction technology. The plant employs hybrid ESP and fabric
filter which maintains stack emission < 50 mg/m3 and HCSD system for ash disposal, which
results in very low consumption of water compared to wet slurry system. The Jharsuguda IPP
would therefore be a zero effluent discharge plant with stack emission.
For actualization of Vision for Global Benchmark Performance, the Company has tied up for
Operation & Maintenance of the station with Evonik Energy Services (India) Pvt. Ltd., a wholly
owned subsidiary of Evonik Energy Services GmbH, Germany having 70 years of experience in
O&M of Coal fired thermal Power Plants of big size.
Table 4:Details of Jharsuguda IPP:Independent power plant, Jahrsuguda, Odisha
Capacity
2400 MW (4X600 MW)
Technology
Thermal Sub critical
EPC contractor
SEPCO III, China
O&M Contractor
Evonik Energy Services India Pvt Ltd
Estimated
Coal
Requirement
estimated project cost
Approx 12.49 mta
INR 82,000 million
2-Talwandi Project:-
Page | 10
Talwandi Sabo Power Limited (TSPL) is implementing a state of the art coal based supercritical
thermal power plant in District Mansa, Punjab, India. This will be the first Supercritical unit and
one of the largest Greenfield power project in the State of Punjab. Power generated from this
project shall be supplied to the Punjab State Electricity Board.
TSPL will use energy efficient and cleaner supercritical technology for the electricity generation.
Super-critical technology utilizes steam at temperature above the critical point of water. The
technology generates same amount of electricity using less coal. The project activity will thus
reduce consumption of fossil fuel (coal) as compared to the conventional sub critical technology
thus making it an environmental friendly and cost efficient technology.
1.6 PROBLEM STATEMENT
2. To identify top 4 competitors of sterlite energy in short term power segment
3. To collect data for all short term power transactions of these 4 competing firms for past 6
months
4. To analyze the trend of weighted average purchase price and weighted average selling
price of power
5. To analyze the trend of trading margins managed by the competitors
6. To study and analyze region wise demand and availability of Electricity to determine
peak shortage and total energy deficit.
7. To study and analyze the power market size and structure.
8. To identify the need and importance of an efficient short term power market.
9. To analyse Volume and Price of short term Power market
10. Benchmarking of Trading Licensee
11. To understand the development process of various developed power market and identify
various successful market tools that can be implemented in India.
12. To identify states for investment opportunities through analysis of different market
parameters influencing the power market.
13. To understand the various risk associated with Short term power market for various
stakeholders.
Page | 11
CHAPTER 2: LITERATURE AND POLICY REVIEW
2.1 LITERATURE REVIEW
Daniel S. Kirschen et al (2000) analyzed the effect that the market structure can have on the
elasticity of the demand for electricity [1]. As electricity markets are liberalized, consumers
become exposed to more volatile electricity prices and may decide to modify the profile of their
demand to reduce their electricity costs. He advocated that elasticities can be taken into
consideration when scheduling generation and setting the price of electricity in a pool based
electricity market. The customers‘ reaction to changes in the price of electricity depends on the
time frame considered. The elasticity of the demand for electricity can be taken into
consideration when the price of electricity is set by a centralized, compulsory pool which
schedules generation on a half-hourly basis for a 24 hour period. Generation is scheduled using a
unit commitment program instead of an optimal power flow. The price computation is carried
out according to the rules of the Electricity Pool of England and Wales. Cutting back on
electricity consumption involves at least one of the following activities: reorganizing production,
adjusting controls, using energy or intermediate product storage systems, calling upon backup
generation or substitute energy sources, cycling equipments. Since all these options are relatively
cumbersome, most consumers are unlikely to react to an increase in price until this increase
becomes significant. There is also a level beyond which load reductions become very difficult if
not impossible to implement. Furthermore, customers are much less likely to increase or
reorganize their production to increase their consumption of electricity in the case of a short-term
price drop than they are to react to a price increase.
B jorganet al (2000) presented flexible electricity contracts (FECs)[2] which require the buyer or
the seller to schedule its decision of a certain time interval, and the scheduling decision is
composed of sequential decision-making processes. Furthermore, the buyer can resell the
electricity obtained from the FEC to spot market; otherwise, the seller can choose between
Page | 12
producing the energy and buying from the spot market. Through this way, the traders of FEC can
optimize their revenue. Since base-load power and peak-load power bring different effects on
power system operation and electricity generation, the value of them is different. So base-load
power and peak-load power should not have the same price. Therefore, the power should be
divided into several continuous blocks that are traded separately at respective prices.
Xian Zhang et al (2003) presented a a model for block flexible electricity contracts (BFEC) and
focuses on pricing the BFEC based on the principle of no-arbitrage[4]. Energy is traded in blocks
according to its time duration at different block prices, which is called block trading. The BFEC
requires the buyer or the seller to schedule its trading amount and the certain block of power at
each time interval. The block trading needs to divide the power into several blocks, the prices of
each power block are obtained from market clearing price. The inherent feature of electricity
commodity makes the price of electricity fluctuates tempestuously, which forces the participants
to confront tremendous financial risk in spot power market. As an efficient risk-managing tool
,forward contract is introduced into power markets. A majority of power exchanges is conducted
through forward contracts in power markets ; therefore, forward contracts have attracted great
interest. The modeling and pricing are the primary contents of forward contracts. The FEC based
on the block trading method is called block flexible electricity contracts(BFECs), which requires
the buyer or seller to schedule its trading amount and the certain block of power at each time
interval. The electricity energy is divided into blocks with continuous time segments, because the
effect of each block on the power system and power market participants varies. It is generally
accepted that the shorter lasting time block such as1-h block power, which is usually used to
balance the peak of load, contributes more to the security of power system than the24-h block
power does. Further more, generating the same quantity power, 1-h block power will costs more
than the 24-h block power due to the cost of unit‘s startup and shutoff. So every block has
different value and cost compared with each other, and the price of the block should vary with its
value and cost. However, the former electricity contracts do not discover the difference of the
power, all of the power at the same time interval is settled by a uniform price.
Page | 13
Jinsu Lee et al (2009) showcased in her studies how to formulate a cross border power trading
system.[7]The West African Power Pool is currently developing the regional electricity market
for its member states. As the basic design for the cross-border power trading system for the West
African Power Pool, the step-by-step evolution, the baseline System and the Full scale System, is
estimated. West Africa region, despite its abundant energy resources, has an unequal
geographical distribution of resources for generating electric power. As a result only a third of
across 14 Economic Community of West African States (ECOWAS) countries has access to
electricity. Power supply for household and industrial uses is vastly different between each
country and distinguished much from the overall regional demand. The West African Power Pool
(WAPP) was established by ECOWAS in order to address the issue of power supply deficiency
within the West African sub-region. It is expected that the market rules for WAPP regional
electricity market will be established by WAPP. If the market rule for WAPP regional electricity
market is finalized, the interchange scheduling and settlement will be reshaped by the market
rule. Generally, in the electricity market environment, the power trading will be based on bidding
mechanism. Through the step-by-step implementation of the WAPPICC System, the WAPP will
achieve its vision to integrate the operation of the national power systems into a unified,
sustainable regional electricity trading.
S. Dehgan et al (2011) suggested congestion relief management(CRM) as one of ancillary
services in power market structure for improving its operation[8]. The CRM maintains the
system operation within the security limits and defines the charge, receiving and paying in non
discriminatory methods which are based on how much of congestion is relieved and caused by
each participant. He compared market-clearing procedures for CRM in terms of only supply side
management and economical efficiency of demand side management to avoid transmission
congestion in an optimum manner. The study concluded that the presence of demand side in
Ancillary Service Market can reduce the congestion relief charge and contract violation, have a
noticeable impact on the short time investment required
to deal with transmission congestion problems and improve the system reliability.
2.2 POLICY REVIEW
Page | 14
Major policies and regulations affecting the trading scenario
Inception of Power Trading Corporation, 1999

Facilitator for market participant in finding counterparts.

Low volume relative to huge demand
Availability Based Tariff, 2002-03

Incentive for generator for efficient operations and central dispatching.

Grid security problems due to overdrawl on high UI charges
Electricity Act, 2003

Identified trading as a distinct licensed activity.

Provided provision for open access

De-Licensing of Generation

Development of multi buyer & multi seller market in power

Introduced trading & competitive bidding for procurement of electricity
National Electricity Policy, 2005

Measures to promote competition aimed at consumer benefits

Promote competition for optimal pricing of power
Open Access Regulations, 2008

Impetus for bilateral trading.

Bilateral trading based on voluntary agreement of participants.

Lacked transparency in price discovery.

Transaction cost hindered smaller players from entering market

Separation of transmission ownership and system operation

Universal open access to transmission networks
Page | 15
Power exchange, 2008

The electricity prices in transparent manner.

Facilitating efficient trading among the player.

Easy access to new entrants is possible.

Clear signals for capacity addition.
National action plan on climate change, 2008

Promotion of renewable power market through power exchanges

Introduction of REC trading
Power market regulations, 2010

Providing a regulatory framework for competitive markets

Guidelines and prudential norms for setting up and operating power exchanges

Guidelines on listing contracts on power exchanges
CERC issues new trading margin regulations
The following are the main features of the new regulations:
1.i) Trading margin shall apply only to short term buy – short term sell contracts for the interstate trading.
ii) Trading margin shall not exceed 4 paisa per unit if the sell price of electricity is less than or
equal to Rs.3 per unit. The ceiling of trading margin shall be 7 paisa per unit in case the sell price
of electricity exceeds Rs.3 per unit.
iii) If more than one trading licensees are involved in a chain of transactions, the ceiling on
trading margin shall include the trading margins charged by all the traders put together
iv) The new ceiling rates on trading margin would come into force after a period of one month so
that the existing contracts can be re-aligned by the parties, if required.
2. CERC had earlier fixed a trading margin of 4 paisa per unit in year 2006.
Page | 16
The earlier regulations were reviewed keeping in view the increase in the risk
faced by traders which is also a function of the prices of electricity. CERC had got done a
detailed study to assess the quantum of default risk, late payment risk, contract dishonor risk and
inflationary risk for arriving at the new ceilings on trading margin.
3. Long term agreements have been exempted from trading margin in order to
facilitate innovative products and contracts for new capacity addition which
involve higher risk in transactions.
Also the trading margin on long term contracts was not consistent with the tariff based
competitive bidding guidelines which envisage discovery of electricity prices through
competition among the suppliers.
CERC checks price volatility in Day-Ahead Markets
The following are the key features of the order:

The price band is only for interstate day-ahead power market.

The price band would be from 10 paise per unit to Rs.8 per unit.

This would be applicable to power exchanges and also to bilateral markets.

The order would lapse after 45 days.
2. This order has been passed by CERC after conducting a public hearing on 8th
September, 2009 and considering the comments/suggestions/objections received
from the stakeholders.
3. The move to initiate this regulatory intervention was based on noticing the
steep increase in short-term power prices and increased weekly price volatility.
4. The order mentions that the Commission is equally conscious of its statutory
obligation to ensure reasonable return for the investors in the sector and assures
that their long term interests, future investment plans and reasonable rate of return are among the
other considerations kept in mind while arriving at the above mentioned caps.
Page | 17
Further, Commission has made it clear that the price caps are being imposed only for day-ahead
transactions and that too for a short period of 45 days.
2.3 Indian Power Market
Table 5: GROWTH RATE OF INSTALLED CAPACITY RESOURCES WISE IN FY
2012-13
FUEL
INSTALLED
AS INSTALLED AS
ON
IN ON MAY-13 IN % GROWTH
MAY-12
MW
MW
COAL
1,13,782.38
131628.39
15.68
GAS
18381.05
20359.85
10.77
OIL
1199.75
1199.75
0.00
1,33,363.18
153187.99
14.87
HYDRO
38990.4
39623.4
1.62
NUCLEAR
4780
4780
0.00
RES(MNRE)
24503.45
27541.72
12.40
TOTAL
2,01,637.03
225133.11
11.65
TOTAL
THERMAL
Figure 1: GROWTH RATE OF INSTALLED CAPACITY RESOURCES WISE IN FY
2012-13
Page | 18
2,50,000.00
2,00,000.00
1,50,000.00
1,00,000.00
50,000.00
0.00
INSTALLED AS ON MAY-12 IN
MW
INSTALLED AS ON MAY-13 IN
MW
According to 17th Electric Power Survey (2007), the energy requirement in the country is
projected to grow at a CAGR of 7.5% during 12th plan period reaching from 9,68,658 Giga Watt
hour (GWH) in FY 2012 to 13,92,065 GWH by FY2017, while peak load requirement is
projected to grow from 1,57,324 MW in FY2012 to 2,23,660 MW in FY 2017 at a CAGR of
7.4%. As on May, 2013 the installed generation capacity in the country constituted 225133,11
MW, of which thermal capacity (coal, gas & diesel) is 1,51,387.99 MW followed by hydel
capacity at 39623.4 MW, renewable energy (wind, small hydro, solar, bio mass, etc) at 27,541.72
MW and nuclear energy at 4,780 MW. The share of Central, State and private sector in the total
installed capacity is 29.04%, 39.68% and 31.28% respectively. The anticipated power supply
position in the Country during the year 2013-14 has been made taking into consideration the
power availability from various stations in operation, fuel availability, and anticipated water
availability at hydro electric stations. A capacity addition of 18432 MW during the year 2013-14
comprising 15234 MW of thermal, 1198 MW of hydro and 2000 MW of nuclear power stations
has been considered.
Page | 19
TABLE 6: COAL BASED THERMAL POWER GENERATION ADDITION BY PRIVATE
SECTOR IN 2013-14
COMMULATIVE
STATE
TARGET
CAP(MW)
A.P
670
CHHATTISGARH 1960
M.P
1320
MAHARASTRA
1830
ODISHA
950
PUNJAB
930
930
670
A.P
CHHATTISGARH
950
1960
M.P
MAHARASTRA
ODISHA
1830
1320
PUNJAB
Figure 2: COAL BASED THERMAL POWER GENERATION ADDITION BY PRIVATE
SECTOR IN 2013-14
Thus, coal is expected to be main fuel for 12th Plan capacity addition too. A shelf of projects with
aggregate capacity of 1,23,135 MW coal based projects have been identified which are likely to
Page | 20
yield benefits during 12th Plan. The total capacity addition for current 12th five year plan is
88,425 MW. In order to bridge the gap between peak demand and peak deficit and provide for an
increased pace of retiring of the old energy inefficient plants, the capacity addition target for the
12th Plan (2012-17) has been fixed at 88,425 MW,‖ according to draft note on energy sector for
the current Plan Period.
However, the capacity addition was just 54,964 MW in the 11the Plan (2007-12) much lower
than set target of 78,700 MW. As per the draft note, out of the projected capacity addition,
thermal sources – coal, lignite and gas – would make up for 71,228 MW while hydro would
account for 11,897 MW. Nuclear power is estimated to be contribute 5,300 MW. More than half
of the total capacity addition would be from the private sector.
Table 7: SECTOR WISE GROWTH IN POWER SECTOR IN 2012-13
%
SECTOR
INSTALLED AS ON MAY-12 IN MW
INSTALLED AS ON MAY-13 IN MW
CENTRAL
60,182.63
65392.94
8.66
STATE
85,918.65
89312.12
3.95
PRIVATE
55,535.75
70428.04
26.82
TOTAL
2,01,637.03
2,25,133.10
11.65
GROWTH
Figure 3: SECTOR WISE GROWTH IN POWER SECTOR IN 2012-13
Page | 21
2,50,000.00
2,00,000.00
1,50,000.00
1,00,000.00
50,000.00
0.00
INSTALLED AS ON MAY-12
IN MW
INSTALLED AS ON MAY-13
IN MW
Source cea(31-05-13)
Figure 4: REGION WISE INSTALLED CAPACITY :-
Total Capacity
Region wise(MW)
1026.94
NR
22605.08
33451.75
WR
SR
28512.6
NR
47696.79
NER
ISLAND
As on 30-04-12
Analysis of load generation balance report-(2013-14)
The assessment of the anticipated power supply position in the Country during the year 2013-14
has been made taking into consideration the power availability from various stations in
operation, fuel availability, and anticipated water availability at hydro electric stations. A
Page | 22
capacity addition of 18432 MW during the year 2013-14 comprising 15234 MW of thermal,
1198 MW of hydro and 2000 MW of nuclear power stations has been considered. The gross
energy generation in the country has been assessed as 975 BU from the power plants in operation
and those expected to be commissioned during the year in consultation with generating
companies/ SEBs and take into consideration the proposed maintenance schedule of the units
during the year. The monthly power requirements for all States/ Uts in terms of peak demand and
energy requirement have been assessed considering the past trend. The power supply position of
each state has been worked out and the assessment of surplus/ shortages has been made which
has been discussed at the foray of Regional Power Committees.
Table 8: Load Generation Balance Report 2013-2014
ALL INDIA POWER SUPPLY POSITION(Load Generation Balance Report 2013-2014)
Energy
REGION
Peak
Surplus(+)/Deficit(
Requirement
Availability
Demand
Met
Surplus(+)/Deficit(-)
MU
MU
MU
%
MW
MW
MW
%
Northern
319885
301418
-18467
-5.8
47500
46879
-621
-1.3
Western
286752
283396
-3356
-1.2
43456
46389
2934
6.8
Southern
309840
250583
-59257
-19.1
44670
33001
-1169
-26.1
Eastern
119632
131880
12248
10.2
18257
19700
1443
7.9
North-Eastern
12424
11024
-1400
-11.3
2251
2025
-226
-10
All India
1048533
978301
-70232
-6.7
144225
140964
-3261
-2.3
-)
source-CEA
*(Considering transmission constraints, anticipated all India peak shortage works out to 6.2 %.)
The above anticipated All India power supply position – which gives assessment of annual deficit
based on overall monthly maximum demand/energy requirement and maximum peak/energy
availability at national level – indicates that the country is expected to experience energy shortage
of 6.7% and peak shortage of 2.3% despite very high shortages likely to be experienced by
Southern Region. This is due to transmission constraints between Northern-North EasternEastern-Western (NEW) Grid and Southern Regional (SR) Grid, which restricts flow of power to
the Southern region. As per analysis we found that NEW grid is likely to be surplus to the extent
of 2.3% during peak hours when considered separately from Southern Region. However, due to
inter-regional transmission constraints between NEW Grid and SR Grid, overall average
Page | 23
anticipated peak shortage of NEW + SR Grid on annual basis works out to 6.2%.
Figure 5: Region wise surplus and deficit:-
REGION SURPLUS/DEFICIT %
15
10
10.2
5
0
-1.2
-5.8
REGION SURPLUS/DEFICIT %
-11.3
-5
-19.1
-10
-15
-20
Figure 6: Anticipated month wise power supply position of India during the
year
2013-14
MONTH
-4
-9.9
Mar-14
-1.2 -1.6
Feb-14
Jan-14
Dec-13
-5.6 -5.2
-2.2 -2.9 -2.9
Nov-13
Oct-13
-2.7
Sep-13
Jul-13
-4.9
Aug-13
-6.4
Jun-13
May-13
-2
Apr-13
0
-7.5
MONTH POWER DEFICIT %
-6
-8
-10
At present the power deficit in southern region is highest (19.1%), northern(5.8%),
Page | 24
western(1.2%), and north eastern (11.3%). But the Eastern region has power surplus of 10.2%.
The main reason for high power deficit in southern region due to unavailability of adequate
transmission corridor.
The peaking shortage would prevail in the Northern, Southern and North-Eastern Regions of
1.2%, 26.1% and 10% respectively. There would be surplus energy of 10.2% in the Eastern region
and all others regions would face energy shortage varying from 1.2 % in the Western region to
19.1% in the Southern region.
The net energy availability and demand met include injection from non-conventional energy
sources, surplus power from CPPs and tied up capacity from IPPs. About 2000 MW capacity of
IPPs likely to be commissioned during the year 2013-14 is not tied up with any entity and it may
become available in the Grid through Power Exchanges/Short Term Open Access mechanism,
thereby mitigating the shortages indicated above.
Figure 7: Region wise Requirement and Availability comparison
1200000
1048533
1000000
800000
600000
400000 319885 286752 309840
200000
Requirement MU
Availability MU
119632
12424
0
Source cea
Page | 25
It may be seen that the hydro rich States having run of river schemes on the Himalayan
rivers viz. Himachal Pradesh, Jammu & Kashmir, and Uttarakhand are surplus in energy during
monsoon period, while they would face severe shortage conditions during the winter low inflow
months when the generation from hydro schemes dwindles to the minimum. Haryana, Himachal
Pradesh, Chhattisgarh, Madhya Pradesh, DVC, West Bengal, Mizoram and Sikkim shall have
both peaking and energy surplus on annual basis. Chandigarh, Delhi, Gujarat, DD, Puducherry,
Manipur and Meghalaya would have surplus in terms of energy whereas Maharashtra, Jharkhand
and Orissa will be in comfortable position in terms of peak on annual basis. All other States in
the country would have electricity shortages of varying degrees both in term of energy and
peaking.
Figure 8 :Requirement of electricity in region wise:-
1200000
1000000
800000
600000
400000
200000
0
Requirement(2013-14) MU
Requirement(2012-13) MU
Requirement(2010-11) MU

Requirement of electricity has increased consistently year after after.
Figure 9:Availability of electricity in region wise:-
Page | 26
1000000
800000
600000
400000
200000
0
Availability(2013-14) MU
Availability(2012-13) MU
Availability(2010-11) MU

Availability of electricity has also increased .
Figure 10:Surplus/Deficit of electricity region wise:20000
0
NR
-20000
WR
SR
ER
NER
All
India
Surplus(+)/Deficit(-) (2013-14)
MU
-40000
Surplus(+)/Deficit(-) (2012-13)
MU
-60000
Surplus(+)/Deficit(-) (2010-11)
MU
-80000
-100000
Page | 27
Figure 11:VOLUME OF SHORT-TERM TRANSACTIONS OF ELECTRICITY IN
INDIA, April-2013
33.88%
Power Exchanges
45.35%
UI
Bilateral
20.78%
Table 9: PRICE OF ELECTRICITY TRANSACTED THROUGH TRADERS, APRIL 2013
PRICE OF ELECTRICITY TRANSACTED THROUGH TRADERS, APRIL 2013
Sr.No
Sale Price of Traders (Rs/kWh),April 2013
1
Minimum
2.9
2
Maximum
8.04
3
Weighted Average
4.55
Table 10: PRICE OF ELECTRICITY TRANSACTED THROUGH TRADERS (TIME-WISE), APRIL 2013
PRICE OF ELECTRICITY TRANSACTED THROUGH TRADERS (TIME-WISE), APRIL 2013
Sr.No
Period of Trade
Sale Price of Traders (Rs/kWh),April 2013
1
RTC
4.6
2
Peak
4.63
3
Off-peak
4.12
Page | 28
Table 11: PRICE OF ELECTRICITY TRANSACTED THROUGH POWER EXCHANGE,APRIL
2013
PRICE OF ELECTRICITY TRANSACTED THROUGH POWER EXCHANGES, APRIL 2013
Price of PXIL(Rs/kwh),Aprill
Sr.No
Period of Trade
Price of IEX (Rs/kWh),April 2013
1
Minimum
1.31
1.31
2
Maximum
19.6
5
3
Weighted Average
3.74
2.71
2013
Table 12: VOLUME AND PRICE OF ELECTRICITY IN TERM AHEAD MARKET OF PXIL,
APRIL 2013
VOLUME AND PRICE OF ELECTRICITY IN TERM AHEAD MARKET OF PXIL, APRIL 2013
Weighted Average
Sr.No
Term ahead contracts
Actual Schedule Volume (MUs)
1
Intra-Day Contracts
1.23
3.3
2
Weekly Contracts
18.48
3.38
Total
19.71
3.38
Price(Rs/kwh)
Table 13:PRICE OF ELECTRICITY TRANSACTED THROUGH UI, APRIL 2013
PRICE OF ELECTRICITY TRANSACTED THROUGH UI, APRIL 2013
Sr.No
Price in NEW grid(Rs/kwh)
Price in SR grid(Rs/kwh)
1
Minimum
0
0
2
Maximum
10.8
10.8
3
Average
2.27
4.29
Page | 29
INDIAN POWER TRADING MARKET
Fixation Of Trading Margin
In exercise of its powers under the Electricity Act, 2003, the CERC has issued new
regulations for fixing the trading margin for inter-state trading in electricity.
CERC had earlier fixed a trading margin of 4 paise per unit in 2006. The earlier regulations
were reviewed keeping in view the increase in risk faced by traders, which is also a function
of the prices of electricity. CERC had got done a detailed study to assess the quantum of
default risk, late payment risk, contract dishonour risk and inflationary risk for arriving at
the new ceilings on trading margin. The Commission also held a public hearing on the
proposals.
Long-term agreements have been exempted from trading margin in order to facilitate
innovative products and contracts for new capacity addition, which involve higher risk in
transactions. Also, the trading margin on long-term contracts was not consistent with the
tariff-based competitive bidding guidelines, which envisage discovery of electricity prices
through competition among the suppliers.
Trading margin shall not exceed 4 paise per unit if the sale price of electricity is less than or
equal to Rs. 3 per unit. The ceiling of trading margin shall be 7 paise per unit in case the
selling price of electricity exceeds Rs. 3 per unit. If more than one trading licensees are
involved in a chain of transactions, the ceiling on trading margin shall include the trading
margins charged by all the traders put together. In other words, traders cannot circumvent the
ceiling by routing the electricity through multiple transactions.
Inter-State Trading Licensees
The Commission has notified the Central Electricity Regulatory Commission (Procedure,
Terms& Conditions for grant of Trading License and other related matters) Regulations,
2009, dated 16.2.2009. As on 31st March 2010, the Commission has awarded trading
Page | 30
licenses to 45 applicants for inter-state trading in electricity. Of the total awarded, 6
licensees have surrendered their license (4 licensees have surrendered their license during
2009-10). Two trading licenses were awarded during the year 2009-10.
Table 14: List of Inter-State Trading Licensees
(As on 15.3.2013)
SL NO.
TRADING LICENSEES
1
Tata Power Trading Company Ltd.
2
Adani Enterprises Ltd.
3
PTC India Limited
4
Reliance Energy Trading Ltd.
5
Vinergy International Private Ltd
6
NTPC Vidyut Vyapar Nigam Ltd.
7
National Energy Trading and Services Ltd.
8
MMTC Limited
9
DLF Power Limited
10
Jindal Steel & Power Limited
11
Sarda Energy & Minerals Ltd.
12
GMR Energy Limited
13
Karam Chand Thapar & Bros. (Coal Sales) Limited
14
Subhash Kabini Power Corporation
15
Special Blasts Ltd.
16
Maheshwary Ispat Limited
17
Instinct Infra & Power Ltd.
18
Essar Electric Power Development
19
Suryachakra Power Corporation
20
JSW Power Trading Company
21
BGR Energy Systems Limited
22
Malaxmi Energy Trading Private
23
Visa Power Limited
Page | 31
24
Pune Power Development Private
25
Patni Projects Pvt. Limited
26
Ispat Energy Limited
27
Greenko Energies Private Limited
28
Vandana Global Limited
29
Vandana Vidhyut Limited
30
Indrajit Power Technology Pvt. Ltd.
31
Adhunik Alloys & Power Ltd.
32
Indiabulls Power Trading Limited
33
Indiabulls Power generation Limited
34
Ambitious Power Trading Company
35
RPG Power Trading. Co. Ltd.
36
Basis Point Commodities Pvt. Ltd.
37
GMR Energy Trading Limited
38
Jain Energy Ltd.
39
Righill Electrics Limited
40
Shyam Indus Power Solutions Pvt.
41
Global Energy Private Limited
42
Knowledge Infrastructure Systems
43
Mittal Processors Private Limited
44
Godawari Power and Ispat Limited
45
Shree Cement Limited
46
PCM Power Trading Corporation
47
Abellon Clean Energy Limited,
48
Jay Polychem (India) Limited, New Delhi
49
Jaiprakash Associates Limited,
50
My Home Power Limited,
51
Customized Energy Solution India
52
BS TransComm Ltd., Hyderabad
53
Chromatic India Limited, Mumbai
54
Kandla Energy and Chemical
Page | 32
55
Marquis Energy Exchange Limited
56
DLF Energy Private Limited,
57
GEMAC Engineering Services Private Limited, Chennai
58
SN Power Markets Pvt. Ltd., Noida
59
Manikaran Power Limited, Kolkata
60
Greta Power Trading Limited
61
Arunachal Pradesh Power
62
Green Fields Power Services Private Limited, Visakhapatnam
63
HMM INFRA LIMITED, Chandigarh
1) Tata Power Trading Company Ltd.
Following are the four major state purchasing power from Tata power trading company
limited during the period Jan-13 to May-13.
Figure 12:Top four power Purchasing state
551.334
600
500
409.657
400
300
MU Purchased
200
118.783
134.553
100
0
West Bengal
Uttarakhand
Rajasthan Dadar & Nagar Haveli
Uttarakhand and West-Bengal remain the largest purchaser of power during the period
Jan to Feb(2013) they purchased 551.334 and 409.66MU respectively followed by
Dadar&Nagar Haveli and Rajasthan.
Figure 13:Volume of Price purchased and weighted average Purchase Price in INR/kWh
offer by the state.
Page | 33
The following graph shows the quantity of power purchased by the top four states and weighted
average price offer by them during the month Jan to Feb (2013).
600
551.334
Quantity of power purchased and price offer INR/kWh
500
409.657
400
300
MU Purchased
200
118.783
134.553
WT.Avg.Purchase price
100
3.648
3.710
3.740
3.880
0
West Bengal
Uttarakhand
Rajasthan
Dadar & Nagar
Haveli
Dadar& Nagar Haveli Purchase with highest price it offers INR 3.880/kWh followed by
Rajasthan Uttarakhand and West Bengal it offers INR 3.74/kWh,3.71/kWh and 3.65/kWh
respectively.
2) NTPC Vidyut Vyapar Nigam Ltd.
Following are the four major states, purchasing power from NTPC vidyut vyapar nigam
ltd. during the period Jan-13 to May-13.
Most of the major purchasing states are from southern region i.e. Tamil nadu, Kerala,
Andhra Pradesh they purchased 865.469, 357.822, 153.282 respectively.
Page | 34
Figure 14: MU Purchased By top four state
1000
900
800
700
600
500
400
300
200
100
0
865.469
357.822
MU Purchased
157.867
153.282
KERALA
AP
TN
WB
Volume of Power purchased and weighted average Purchase Price in INR/kWh offer by
the state.
The following graph shows the quantity of power purchased by the top four states and weighted
average price offer by them during the month Jan to Feb (2013).
Figure 15: Quantity of power purchased and price offer INR/kWh
1000
900
800
700
600
500
400
300
200
100
0
865.469
Quantity of power purchased and price offer INR/kWh
MU Purchased
357.822
Wt. Avg. Purchase Price
157.867
153.282
4.991
KERALA
5.417
4.277
AP
TN
3.811
WB
Page | 35
Andhra Pradesh purchased at Rs.5.417/kWh for 153.282MU whereas Kerala, Tamil Nadu and
West Bengal purchased at Rs.4.991/kWh,4.277/kWh and 3.811/kWh for 357.822, 865.469 and
157.867MU‘s of Power.
3)National Energy Trading and Service:Following are the five major states, purchasing power from National Energy Trading and
Service during the period Jan-13 to May-13.
From southern region i.e. Tamil Nadu, Andhra Pradesh purchased 11.09789 and 33.9504
MU respectively and from Northern region Delhi, Punjab and U.P purchased
23.327015,12.128703 and 4.40937 MU‘s respectively.
Figure 16:Volume of Power purchased by top 5 states through NETS:
40
33.9504
35
30
23.327015
25
20
15
12.128703
11.09789
10
MU Purchased
4.40937
5
0
Tamil Nadu
Andhra
Pradesh
U.P.
Delhi
Punjab
Figure 17:Volume of Power Purchased and Weighted Average Purchase Price
in INR/kWh offer by the state:-
Page | 36
40
Quantity of power purchased and price offer INR/kWh
33.9504
35
30
23.327015
25
20
MU Purchased
15 11.09789
10
5.145
5
12.128703
5.43 4.40937
3.1
4.05
Weighted Avg. Purchase Price
3.93
0
Tamil
Nadu
Andhra
Pradesh
U.P.
Delhi
Punjab
Tamil Nadu, Andhra Pradesh, U.P, Delhi and Punjab purchased 11.09789, 33.9504, 4.4.0937,
23.327015,
12.128703
MU‘s
respectively
at
INR
5.145/kWh,5.43/kWh,3.1/kWh,4.05/kWh,3.93/kWh.
4)PTC India Limited.
Following are the five major states, purchasing power from PTC India ltd. during the
period Jan-13 to May-13.
Figure 18: Volume of electricicty Purchased
MU Purchased
800.00
700.00
600.00
500.00
400.00
300.00
200.00
100.00
0.00
674.72
500.43
436.49
323.62
206.13221
Andhra
Pradesh
HIMACHAL
PRADESH
KERALA
MU Purchased
RAJASTHAN UTTRAKHAND
Page | 37
Figure 19:Volume of Power purchased and Weighted Average Purchase Price
in INR/kWh offer by the state.
800.00
700.00
600.00
500.00
400.00
300.00
200.00
100.00
0.00
674.72
500.43
436.49
323.62
206.13221
MU Purchased
5.31
3.26
4.94
3.78
3.83
Figure 20: Weighted avg.Purchase price at trading licencees
6
5.43
5.43
5
4
Wt. avg Purchasing price
4.89
4.2
4.1
3.73
4.3
4.2
4.38
4.37
3.73
3.7
3
4.53
4.15
3.48
3.1
4.28
4.15
3.76
Tata trading
NVVNL
PTC
NETS
2
1
0
0
Jan-13
Feb-13
Mar-13
Apr-13
May-13
Page | 38
INDIAN POWER EXCHANGE
Introduction:
On 6th February 2007, the CERC issued guidelines for grant of permission to set up power
exchanges in India. Financial Technologies (India) Ltd responded by proposing then tentatively
named 'Indian Power Exchange Ltd' and applied for permission to set it up and operate it within
the parameters defined by CERC and other relevant authorities. Based on the oral hearing on
July 10, the CERC accorded its approval vide its order dated 31st August, 2007. IEX thus moved
from the conceptual level to firmer grounds. On 9th June 2008 CERC accorded approval to IEX
to commence its operations and 27th June 2008 marked its presence in the history of Indian
Power Sector as Indian Energy Exchange Ltd (IEX), India‘s first-ever power exchange starts
operating.
A Power Exchange shall function with the following objectives:
1. Ensure fair, neutral, efficient and robust price discovery
2. Provide extensive and quick price dissemination
3. Design standardised contracts and work towards increasing liquidity in such contracts
Explanation: Liquidity is a measure of ease of entering or exiting into a transaction
(generally large transaction) with minimal impact in the market price of the transacted contract.
Power exchanges are categorised as follows:
1. M/s Indian Energy Exchange Ltd.(IEX),New Delhi
2. Power Exchange India Ltd.(PXIL), Mumbai which are operational in India.
PRODOUCTS OF IEX:
Day Ahead Market:
On a daily basis the Exchange will offer a double side closed auction for delivery on the
following day, which is termed as day-ahead market. Price discovery would be through double
side bidding and buyers and suppliers shall pay/receive uniform price.
Page | 39
Day Ahead Market operations will be carried out in accordance with the ‗Procedure for
scheduling of collective transactions‘ issued by the Central Transmission Utility (PGCIL),
‗CERC (Open Access in inter-State Transmission) Regulations, 2008‘ ,its modifications issued
from time to time and the Bye-Laws, Rules and Business Rules of the Exchange.
Process of Closed-Bidding Auction:
Bid accumulation period(Bidding phase): During the auction sessions on each Trading Day,
bids entered by Members on the IEX Trading Platform are automatically stored in the Central
Order Book without giving rise to Contracts. During this phase, bids entered can be revised or
cancelled. Bid accumulation period shall start at 10.00 AM and will end at 12.00 Noon.
Auction Period: At the end of the bidding session, the IEX Trading Platform will seek to match
bids for each 15 minute time block. After the price determination phase is concluded, the
Members, whose bids have been partially or fully executed, will be provided all relevant trade
information regarding each contract traded on the IEX Trading Platform.
Price Determination Process (Provisional): All purchase bids and sale offers will be
aggregated in the unconstrained scenario. The aggregate supply and demand curves will be
drawn on Price-Quantity axes. The intersection point of the two curves will give Market Clearing
Price (MCP) and Market Clearing Volume (MCV) corresponding to price and quantity of the
intersection point. Results from the process will be preliminary results. Based on these results the
Exchange will work out provisional obligation and provisional power flow. Funds available in
the settlement account of the Members shall be checked with the Clearing Banks and also
requisition for capacity allocation shall be sent to the NLDC. In case sufficient funds are not
available in the settlement account of the Member then his bid (s) will be deleted from further
evaluation procedure.
Page | 40
Price Determination Process (Final): Based on the transmission capacity reserved for the
Exchange by the NLDC on day ahead basis by 2.00 PM, fresh iteration shall be run at 2.30 PM
and final Market Clearing Price and Volume as well as Area Clearing Price and Volume shall be
determined. These Area Clearing Prices shall be used for settlement of the contracts.
Settlement:
On receipt of final results, obligations shall be sent to Banks for Pay In from buying Members at
2.30 PM and will take confirmation of the same from the Bank. At 3.00 PM final results will be
sent to NLDC / SLDCs for incorporating in final schedules. Once a transaction is scheduled it
shall be considered as deemed deliver.
TERM AHED MARKET: This market segment will cover all electricity contracts except those
mentioned in the Day Ahead Market segment. This will cover market timeframes of intra-day,
day-ahead contingency, daily, weekly etc. as allowed by the Commission. The Term Ahead
Market will operate in accordance with the procedures issued by CTU for „Scheduling of
Bilateral Transactions‟. All terms and conditions of the contracts including trading sessions,
matching rules, margin requirement and delivery procedure etc, will be as per specific rules
mentioned herein.
Page | 41
Contracts: The Exchange shall make the contracts as specified in this section available for
trading as per the trading calendar. These contracts will be traded in accordance with provisions
of trading as specified in the respective Contract Specification. The trade sessions, matching
rules applied in each trade session for concluding the contracts, risk management and settlement
for such contracts will be as per specific contract specifications provided herein. The delivery of
such contracts will be in accordance with CERC (Open Access in Inter-State Transmission)
Regulations, 2008, as amended from time to time and relevant procedures issued by CTU and by
Open Access Regulations of concerned State. The Exchange holds the right to modify all other
parameters except those specified in regulation 7 of CERC (Power Market) Regulation, 2010.
These contracts will be further differentiated on time of day basis (Peak and Off-Peak basis),
day-of-the week basis (weekday, week-end and holiday). Following contracts shall be available
for trading in Term-Ahead Market:
Day-Ahead Contingency Contracts: The Exchange shall make the daily contracts available for
trading upto a period specified by CERC for delivery of electricity for defined blocks of hours of
the day. The Exchange will carry out trading in such contracts either through „Uniform Price
Step Auction‟ or „Continuous Trade‟ sessions or a combination of both depending on market
feedback. The timeline for trade matching sessions will be specified in Contract Specifications.
They will be sent for scheduling in accordance with CERC (Open Access in Inter-State
Transmission) Regulation, 2008, as amended from time to time and relevant procedures issued
by CTU as specified in the contract specifications. The contracts may contain provisions
allowing quantity variation in delivery. The Exchange holds the right to modify parameters as
specified by CERC.
Weekly Contracts: The Exchange shall make the weekly contracts available for trading
maximum upto a period specified by CERC for delivery of electricity for defined blocks of hours
on all defined week-days and/or weekends of the week. The Exchange will carry out trading in
such contracts through „Uniform Price Step Auction‟ or „Continuous Trade‟ sessions or a
combination of both as approved by CERC. The timeline for trade matching sessions will be
specified in Contract Specifications. They will be sent for scheduling in accordance with CERC
Page | 42
(Open Access in Inter-State Transmission) Regulation, 2008, as amended from time to time and
relevant procedures issued by CTU as specified in the contract specifications. The contracts may
contain provisions allowing quantity variation in delivery. The Exchange holds the right to
modify parameters as specified by CERC.
Daily Contracts: The Exchange shall make the daily contracts available for trading upto a
period specified by CERC for delivery of electricity for defined blocks of hours of the day. The
Exchange will carry out trading in such contracts either through „Uniform Price Step Auction‟ or
„Continuous Trade‟ sessions or a combination of both depending on market feedback. The
timeline for trade matching sessions will be specified in Contract Specifications. They will be
sent for scheduling in accordance with CERC (Open Access in Inter-State Transmission)
Regulation, 2008, as amended from time to time and relevant procedures issued by CTU as
specified in the contract specifications. The contracts may contain provisions allowing quantity
variation in delivery.
Weekly Contracts: The Exchange shall make the weekly contracts available for trading
maximum up to a period specified by CERC for delivery of electricity for defined blocks of
hours on all defined week-days and/or weekends of the week. The Exchange will carry out
trading in such contracts through „Uniform Price Step Auction‟ or „Continuous Trade‟ sessions
or a combination of both as approved by CERC. The timeline for trade matching sessions will be
specified in Contract Specifications. They will be sent for scheduling in accordance with CERC
(Open Access in Inter-State Transmission) Regulation, 2008, as amended from time to time and
relevant procedures issued by CTU as specified in the contract specifications. The contracts may
contain provisions allowing quantity variation in delivery. The Exchange holds the right to
modify parameters as specified by CERC.
Page | 43
Figure 21:Indian Energy exchange price analysis Region Wise:6.72
6.52
7
6
5.12
5
4
3
3.4
3.02 3.09
2.3
3.47
3.11 3.04
2.27
3.39
3.15 3.22
3.6
2.49
2010
3.32
3.18
3.16
2.43
2011
2012
2013
2
1
0
north east
eastern
northern
southern
Western
Page | 44
Figure 22:Indian Energy exchange price analysis Region Wise Last 5 Year :-
10.000
9.000
8.000
7.000
6.000
5.000
2013
2012
4.000
2011
3.000
2010
2.000
2009
1.000
0.000
2008
From the above graph we can see that the weighted average price per unit of electricity is highest
in southern region due to huge power deficit in the southern region. In 2013 the highest price for
unit of power sold is 6.867/KWH in S2 region. The lowest price is in the region is N3,where the
unit price is 1.969/KWH. Before delivery date of 24/8/2011, N3 region was part of N1 region
and W3 region was part of W1 region.
Figure 23:REGION WISE VOLUME OF ELECTRICITY SOLD BY IEX(2008-13)
Page | 45
25000000
20000000
15000000
2013
2012
10000000
2011
2010
5000000
2009
2008
0
The most volume of power (18096422.39 MW) sold t on unconstrained market price in
2013,followed by S1 region where 2949565.28 MW and also in N1 region the total volume of
power sold is 2672087.85 MW. This trend shows that lot of registered member of exchange
prefer to buy and sell power in short term basis in 15-minutes time block. Also the rise in
volume of power sell in N1 and S1 shows that there is huge demand of power in northern and
southern region due to power deficit.
Page | 46
Long Term Open Access
Long term market serves as a major platform to procure and sell power to the utilities. As of
now, the available power procuring arrangements in the long term market are:
1. Traditional PPAs between genco and discom-Regulated: Until recently ,the long term
market had a single arrangement called the regulated PPA to procure and sell power.This
PPA is a legal contract between an electricity generator and a discom. Such agreements
plays a key role in the financial closure of generation projects .
2. Long/medium term PPAs between genco and traders and PSAs between trader and
discom: However, while analysing the upcoming/proposed capacities, there is slow
transition from regulated PPAs (genco discom) to bilateral contracts involving
traders(genco trader discom/industrial consumer/exchange). Traders such as PTC,Tata
Power Trading and Reliance Trading had executed many such LT-PPA with generators
and their strategy is to be in open position in the market and sell the contracted power in
Page | 47
small quantities for shorter duration to different consumers at high price. PTC leads in
dealing long –term power and has entered into many MoUs/PPAs with generators to
procure long –term power.
3. Long /medium term PPAs between genco and discom i.e. competitive bidding: MoP has
issued the competitive bidding guidelines contemplated under Section 63 of the Act,
titled ―Guidelines for Determination of Tariff by Bidding Process for Procurement of
Power by Distribution Licensees‖. As per these guidelines, the discom can invite bids
from prospective sellers both on long term and medium term basis. As of now, the total
capacity coming up through the competitive bidding regime is to the tune of
30GW.Hence, competitive bidding is gaining momentum, and stakeholders‘ generic
views on this are presented below:
 From Buyer’s side: This new regime has helped them to discover competitive tariffs and has
considerably reduced the discom‘s cost of power procurement. As procurement by more than one
distribution utility is permitted, it would further bring down the aggregate efforts taken by
individual discoms in the state.
 From Developer’s side: Both the private segment and public sector companies would have to
forego the profit margin as fixed in the regulated cost-plus structure. As some of risks are
thoroughly minimised through competitive regime, the established private players would not get
much affected by this transition; instead, could arrange cheaper finances for the project. As
certain technocommercial competencies are required to minimise the overall project cost and to
arrive at lowest profitable tariff, the small players and new entrant would find it hard to compete
with the established players.
 From Traders side: This regime has helped to earn an unregulated profit margin for the
entire transaction. As traders are allowed to participate in Case 1 bidding, they can also contract
capacities from one or more generators and, in turn, bid for supplying to discom .
Guidelines for Determination of Tariff by Bidding Process for Procurement of Power by
Page | 48
Distribution Licensees
Bidding Process
TWO STAGE PROCESS:
For long-term procurement under these guidelines, a two-stage process featuring separate
Request for Qualification (RFQ) and Request for Proposal (RFP) stages shall be adopted for the
bid process under these guidelines. The procurer may, at his option, adopt a single stage tender
process for medium term procurement, combining the RFP and RFQ processes. Procurer or
authorized representative shall prepare bid documents including the RFQ and RFP in line with
these guidelines and standard bid documents.
The procurer shall publish a RFQ notice in at least two national newspapers, company website
and preferably in trade magazines also to accord it wide publicity. The bidding shall necessarily
be by way of International Competitive Bidding (ICB). For the purpose of issue of RFQ
minimum conditions to be met by the bidder shall be specified by the procurer in the RFQ notice.
Procurer shall provide only written interpretation of the tender document to any bidder /
participant and the same shall be made available to all other bidders. All parties shall rely solely
on the written communication and acceptances from the bidders.
Standard documentation to be provided by the procurer in the RFQ shall include,
(i) Definition of Procurer‘s requirements, including:

Quantum of electricity proposed to be bought in MW. To provide flexibility to the
bidders, this may be specified as a range, within which bids would be accepted. Further,
the procurer may also provide the bidders the flexibility to bid for a part of the tendered
quantity, subject to a given minimum quantity.

The procurer may separately specify distinct base load requirements and peak load
requirements through the same bid process. Seasonal power requirements, if any, shall
also be specified;
Page | 49

Term of contract proposed; (as far as possible, it is advisable to go for contract coinciding
with life of the project in case of long term procurement). The bidder shall be required to
quote tariff structure for expected life of the project depending upon fuel proposed by
him. The expected life project is estimated to be 15 years for gas/liquid fuel based
projects, 25 years for coal based projects and 35 years for hydro projects.

Normative availability requirement to be met by seller (separately for peak and off-peak
hours, if necessary);

Definition of peak and off-peak hours;

Expected date of commencement of supply;

Point(s) where electricity is to be delivered;

Wherever applicable, the procurer may require construction milestones to be specified by
the bidders;

Financial requirements to be met by bidders including, minimum net-worth, revenues, etc
with necessary proof of the same, as outlined in the bid documents;
(ii) Model PPA proposed to be entered into with the seller of electricity. The PPA shall include
necessary details on:

Risk allocation between parties;

Technical requirements on minimum load conditions;

Assured offtake levels;

Force majeure clauses as per industry standards;

Lead times for scheduling of power;

Default conditions and cure thereof, and penalties;

Payment security proposed to be offered by the procurer.
(iii) Period of validity of offer of bidder;
Page | 50
(iv) Requirement of transfer of assets by the selected bidder (if any) to the procurer at the end of
the term of the PPA.
(v) Other technical, operational and safety criteria to be met by bidder, including the provisions
of the IEGC/State Grid Code, relevant orders of the Appropriate Commission (e.g – the ABT
Order of the CERC), emission norms, etc., as applicable.
(vi) The procurer may, at his option, require demonstration of financial commitments from
lenders at the time of submission of the bids. This would accelerate the process of financial
closure and delivery of electricity;
(vii) The procurer and the supplier may exercise exit option subject to the condition that the new
player satisfies all RFP conditions.
RFP shall be issued to all bidders who have qualified at the RFQ stage. In case the bidders seek
any deviations and procurer finds that deviations are reasonable, the procurer shall obtain
approval of the Appropriate Commission before agreeing to deviation. The clarification/revisedbidding document shall be distributed to all who had sought the RFQ document informing about
the deviations and clarifications. Wherever revised bidding documents are issued, the procurer
shall provide bidders at least two months after issue of such documents for submission of bids.
Standard documentation to be provided by the procurer in the RFP shall include,
(i) Structure of tariff to be detailed by bidders;
(ii)
PPA
proposed
to
be
entered
with
the
selected
bidder.
The model PPA proposed in the RFQ stage may be amended based on the inputs received from
the interested parties, and shall be provided to all parties responding to the RFP. No further
amendments shall be carried out beyond the RFP stage;
(iii)
Payment
security
to
be
made
available
by
the
procurer.
The payment security indicated in the RFQ stage could be modified based on feedback received
in the RFQ stage. However no further amendment to payment security would be permissible
beyond the RFP stage.
Page | 51
(iv) Bid evaluation methodology to be adopted by the procurer including the discount rates
for evaluating the bids.
The bids shall be evaluated for the composite levellised tariffs combining the capacity and
energy components of the tariff quoted by the bidder. In case of assorted enquiry for
procurement of base load, peak load and seasonal power, the bid evaluation for each type of
requirement shall be carried out separately. The capacity component of tariffs may feature
separate non-escalable (fixed) and escalable (indexed) components. The index to be adopted for
escalation of the escalable component shall be specified in the RFP. For the purpose of bid
evaluation, median escalation rate of the relevant fuel index in the international market for the
last 30 years for coal and 15 years for gas / LNG (as per CERC‘s notification in (vi) below) shall
be used for escalating the energy charge quoted by the bidder. However this shall not apply for
cases where the bidder quotes firm energy charges for each of the years of proposed supply, and
in such case the energy charges proposed by the bidder shall be adopted for bid evaluation. The
rate for discounting the combination of fixed and variable charges for computing the levellised
tariff shall be the prevailing rate for 10 year GoI securities;
(v) The RFP shall provide the maximum period within which the selected bidder must
commence supplies after the PPA is entered into by the procurer with the selected bidder, subject
to the obligations of the procurer being met. This shall ordinarily not be less than four years from
the date of signing of the PPA with the selected bidder in case supply is called for long term
procurement. The RFP shall also specify the liquidated damages that would apply in event of
delay in supplies.
(vi) Following shall be notified and updated by the CERC every six months for the purpose of
bid evaluation:
1.Applicable discount rate
2.Escalation rate for coal
3.Escalation rate for gas/LNG
4. Inflation rate to be applied to indexed capacity charge component.
Page | 52
Bid submission and evaluation

To ensure competitiveness, the minimum number of qualified bidders should be at least
two other than any affiliate company or companies of the procurer. If the number of
qualified bidders responding to the RFQ/RFP is less than two, and procurer still wants to
continue with the bidding process, the same may be done with the consent of the
Appropriate Commission.

Formation of consortium by bidders shall be permitted. In such cases the consortium
shall identify a lead member and all correspondence for the bid process shall be done
through the lead member. The procurer may specify technical and financial criteria, and
lock in requirements for the lead member of the consortium, if required.

The procurer shall constitute a committee for evaluation of the bids with at least one
member external to the procurer‘s organisation and affiliates. The external member shall
have expertise in financial matters / bid evaluation. The procurer shall reveal past
associations with the external member - directly or through its affiliates - that could
create potential conflict of interest.

Eligible bidders shall be required to submit separate technical and price bids. Bidders
shall also be required to furnish necessary bid-guarantee along with the bids. Adequate
and reasonable bid-guarantee shall be called for to eliminate non-serious bids. The bids
shall be opened in public and representatives of bidders desiring to participate shall be
allowed to remain present.

The technical bids shall be scored to ensure that the bids submitted meet minimum
eligibility criteria set out in the RFP documents on all technical evaluation parameters.
Only the bids that meet all elements of the minimum technical criteria set out in the RFP
shall be considered for further evaluation on the price bids.

The price bid shall be rejected if it contains any deviation from the tender conditions for
submission of price bids.

Wherever applicable, the price bid shall also specify the terminal value payable by the
Procurer for the transfer of assets by the selected bidder in accordance with the terms of
the RFP.
Page | 53

The bidder may quote the price of electricity at the generating station bus-bar (net of
auxiliaries), or at the interface point with the State transmission network. For purposes of
standardization in bid evaluation, the tariffs shall be compared at the interface point of
the generator/supplier with the State transmission network. In case the bidder quotes his
rate at the generating station bus-bar, normative transmission charges for the
regional/inter-regional network, if applicable, based on the prevailing CERC orders shall
be added to the price bid submitted. The charges for the State transmission network shall
be payable by the procurer, and shall not be a part of the evaluation criteria.
The bidder who has quoted lowest levellised tariff as per evaluation procedure, shall be
considered for the award. The evaluation committee shall have the right to reject all price bids if
the rates quoted are not aligned to the prevailing market prices.
Deviation from process defined in the guidelines
In case there is any deviation from these guidelines, the same shall be subject to approval by the
Appropriate Commission. The Appropriate Commission shall approve or require modification to
the bid documents within a reasonable time not exceeding 90 days.
Arbitration
The procurer will establish an Amicable Dispute Resolution (ADR) mechanism in accordance
with the provisions of the Indian Arbitration and Conciliation Act, 1996. The ADR shall be
mandatory and time-bound to minimize disputes regarding the bid process and the
documentation thereof.
If the ADR fails to resolve the dispute, the same will be subject to jurisdiction of the appropriate
Regulatory Commission under the provisions of the Electricity Act 2003.
Time Table for Bid Process
A suggested time-table for the bid process is indicated below. The procurer may give extended
time-frame indicated herein based on the prevailing circumstances and such alterations shall not
be construed to be deviation from these guidelines.
Page | 54
Elapsed Time from
Event
Zero date
Publication of RFQ
Zero date
Submission of Responses of RFQ
60 days
Short listing based on responses
and issuance of RFP
Bid clarification, conferences etc
Final clarification and revision of
RFP
90 days
150 days
180 days
Technical and price bid submission 360 days
Shortlisting of bidder and issue of
LOI
Signing of Agreements

390 days
425 days
A suggested time-table for the Single stage bid process is indicated below. The procurer
may give extended time-frame indicated herein based on the prevailing circumstances
and such alterations shall not be construed to be deviation from these guidelines.
Event
Publication of RFP
Bid clarification, conferences etc.
& revision of RFP
Elapsed Time from
Zero date
Zero date
90 days
Page | 55
Technical and price bid submission 180 days
Short-listing of bidder and issue of
LOI
Signing of Agreements
210 days
240 days
Contract award and conclusion

The PPA shall be signed with the selected bidder consequent to the selection process in
accordance with the terms and conditions as finalized in the bid document before the
RFP stage.

Consequent to the signing of the PPA between the parties, the evaluation committee
shall provide appropriate certification on adherence to these guidelines and to the bid
process established by the procurer.

The procurer shall make evaluation of bid public by indicating terms of winning bid and
anonymous comparison of all other bids. The procurer shall also make public all
contracts signed with the successful bidders.

The final PPA along with the certification by the evaluation committee shall be
forwarded to the Appropriate Commission for adoption of tariffs in terms of Section 63
of the Act.
Medium Term Open Access
MTOA (Medium Term Open Access) application for connectivity comes under The Regulation
―Central Electricity Regulatory Commission (Grant of Connectivity, Long-term Access and
Medium-term Open Access in inter-State Transmission and related matters) Regulations, 2009.‖
As per the CERC regulation a Generating station of installed capacity 250 MW and above,
including a captive generating plant of exportable capacity of 250 MW and above or a bulk
consumer in respect of grant of connectivity and a generating station including a captive
generating plant, a consumer, an Electricity Trader or a distribution licensee, in respect of long-
Page | 56
term access or medium-term open access , as the case may be. A ―Bulk consumer‖ who intends
to avail supply of a minimum load of 100 MW from the Inter-State Transmission System can
apply for connectivity.
The medium term open access( MTOA) means the right to use the inter-State transmission
system for a period exceeding 3 months but not exceeding 3 years. The generating station
including captive generating plant or a bulk consumer, seeking connectivity to the inter-State
transmission system cannot apply for long-term access or medium-term open access without
applying for connectivity. Provided that a generating station, including captive generating plant
or a bulk consumer, seeking connectivity to the inter-State transmission. The nodal agency to
grant of connectivity, for medium term open access to the inter-State transmission system shall
be the Central Transmission Utility.
The application of connectivity should accompanied by a non refundable application fee payable
in the name and in the manner to be laid down by the Central Transmission Utility in the detailed
procedure.
APPLICATION FEE FOR MTOA
Quantum of Power
S.No
to
be injected/off
taken
into/from
ISTS
1
Up to 100 MW
More than 100MW
2
up to 500 MW
Application fee (Rs. in lakh)
FOR
Medium-term
CONNECTIVITY Open Access
2
1
3
2
6
3
9
4
More than 100MW
and up to 500 MW
3
More
4
MW
than
1000
Page | 57
The application form shall be processed within 40 days by nodal agency for medium term open
access.
Procedure for Grant of Connectivity:
The application for connectivity shall contain details such as, proposed
geographical location of the applicant, quantum of power to be interchanged that is the quantum
of power to be injected in the case of a generating station including a captive generating plant
and quantum of power to be drawn in the case of a bulk consumer, with the inter-State
transmission system and such other details as may be laid down by the Central Transmission
Utility in the detailed procedure. Provided that in cases where once an application has been filed
and there after there has been any material change in the location of the applicant or change, by
more than 100 MW in the quantum of power to be interchanged with the inter-State transmission
system, the applicant shall make a fresh application, which shall be considered in accordance
with these regulations. On receipt of the application, the nodal agency shall, in consultation and
through coordination with other agencies involved in inter-State transmission system to be used,
including State Transmission Utility, if the State network is likely to be used, process the
application and carry out the necessary interconnection study as specified in the Central
Electricity Authority (Technical Standards for Connectivity to the Grid) Regulations, 2007.
While granting connectivity, the nodal agency shall specify the name of the sub-station or
pooling station or switchyard where connectivity is to be granted. In case connectivity is to be
granted by looping-in and looping-out of an existing or proposed line, the nodal agency shall
specify the point of connection and name of the line at which connectivity is to be granted. The
nodal agency shall indicate the broad design features of the dedicated. The applicant and all
Inter-State Transmission Licensees including the Central Transmission Utility shall comply with
the provisions of Central Electricity Authority (Technical Standards for Connectivity to the Grid)
Regulations, 2007. The applicant or inter-State transmission licensee, as the case may be, shall
sign a connection agreement with the Central Transmission Utility or inter-State transmission
licensee owning the sub-station or pooling station or switchyard or the transmission line as
identified by the nodal agency where connectivity is being granted Provided that in case
Page | 58
connectivity of a generating station, including captive generating plant or bulk consumer is
granted to the inter-State transmission system of an inter-State transmission licensee other than
the Central Transmission Utility, a tripartite agreement as provided in the Central Electricity
Authority (Technical Standards for Connectivity to the Grid) Regulations, 2007 shall be signed
between the applicant, the Central Transmission Utility and such inter-State transmission
licensee. The grant of connectivity shall not entitle an applicant to interchange any power with
the grid unless it obtains long-term access, medium-term open access or short-term open access.
A generating station, including captive generating plant which has been granted connectivity to
the grid shall be allowed to undertake testing including full load testing by injecting its infirm
power into the grid before being put into commercial operation, even before availing any type of
open access, after obtaining permission of the concerned Regional Load Despatch Centre, which
shall keep grid security in view while granting such permission. This infirm power from a
generating station or a unit thereof, other than those based on non-conventional energy sources,
the tariff of which is determined by the Commission, will be governed by the Central Electricity
Regulatory Commission (Terms and Conditions of Tariff) Regulations, 2009. The power
injected into the grid from other generating stations as a result of this testingshall also be charged
at UI rates. An applicant may be required by the Central Transmission Utility to construct a
dedicated line to the point of connection to enable connectivity to the grid Provided that a
thermal generating station of 500 MW and above and a hydro generating station of 250 MW and
above, other than a captive generating plant, shall not be required to construct a dedicated line to
the point of connection and such stations shall be taken into account for coordinated transmission
planning by the Central Transmission Utility and Central Electricity Authority.
Applications for long-term access or medium-term open access shall be processed on first-comefirst-served basis separately for each of the aforesaid types of access: Provided that applications
received during a month shall be construed to have arrived concurrently.
APPLICATION PROCEDURE FOR MTOA:
1) The application for grant of medium-term open access shall contain such details as may be
laid down under the detailed procedure and shall, in particular, include the point of injection into
Page | 59
the grid, point of drawl from the grid and the quantum of power for which medium-term open
access has been applied for.
2) The start date of the medium-term open access shall not be earlier than 5 months and not later
than 1 year from the last day of the month in which application has been made.
3) On receipt of the application, the nodal agency shall, in consultation and through coordination
with other agencies involved in inter-State transmission system to be used, including State
Transmission Utility, if the State network is likely to be used, process the application and carry
out the necessary system studies as expeditiously as possible so as to ensure that the decision to
grant or refuse medium-term open access.
4) On being satisfied that the requirements specified under clause (2) of regulation 9 are met, the
nodal agency shall grant medium-term open access for the period stated in the
application.Provided that for reasons to be stated in writing, the nodal agency may grant
medium-term open access for a period less than that sought for by theapplicant; Provided further
that the applicant shall sign an agreement for medium term open access with the Central
Transmission Utility in case medium-term open access is granted by the Central Transmission
Utility, in accordance with the provision as may be made in the detailed procedure. While
seeking medium-term open access to an inter-State transmission licensee, other than the Central
Transmission Utility, the applicant shall sign a tripartite medium term open access agreement
with the Central Transmission Utility and the inter-State transmission licensee. The medium–
term open access agreement shall contain the date of commencement and end of medium-term
open access, the point of injection of power into the grid and point of drawl from the grid, the
details of dedicated transmission lines required, if any, the bank guarantee required to be given
by the applicant and other details in accordance with the detailed procedure. Immediately after
grant of medium-term open access, the nodal agency shall inform the Regional Load Despatch
Centres and the State Load Despatch Centres concerned so that they can consider the same while
processing requests for short- term open access received under Central Electricity Regulatory
Commission (Open Access in inter-State transmission) Regulations, 2008 as amended from time
to time.
5) Medium-term customer may arrange for execution of the dedicatedtransmission line at its own
risk and cost before the start date of the medium term open access.
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6) On the expiry of period of the medium-term open access, the medium-termcustomer shall not
be entitled to any overriding preference for renewal of theterm.
7) A medium-term customer may relinquish rights, fully or partly, by giving atleast 30 days prior
notice to the nodal agency. Provided that the medium-term customer relinquishing its rights shall
pay applicable transmission charges for the period of relinquishment or 30 days which ever is
lesser.
8) When for the reason of transmission constraints or in the interest of grid security, it becomes
necessary to curtail power flow on a transmission corridor, the transactions already scheduled
may be curtailed by the Regional Load Despatch Centre. Subject to provisions of the Grid Code
and any other regulation specified by the Commission, the short-term customer shall be curtailed
first followed by the medium-term customers, which shall be followed by the long term
customers and amongst the customers of a particular category, curtailment shall be carried out on
pro rata basis.
9) The transmission charges for use of the inter-State transmission system shall be recovered
from the long-term customers and the medium-term customers in accordance with terms and
conditions of tariff specified by the Commission from time to time. Provided that if the State
network is also being used in the access as a part of inter-State transmission system for the
conveyance of electricity across the territory of an intervening State as well as conveyance
within the State which is incidental to such inter-State transmission of electricity, recovery of
charges for such State network and terms and conditions thereof shall be in accordance with the
regulation as may be specified by the Commission under section 36 of the Act for intervening
transmission facilities, if such charges and terms and conditions cannot be mutually agreed upon
by the licensees; Provided that any disagreement on transmission charges for such State network
as specified above, shall not be the sole reason for denying access and either party may approach
the Commission for determination of transmission charges for such State network.
10) Subject to the provisions of these regulations, the Central Transmission Utility shall submit
the detailed procedure to the Commission for approval within 60 days of notification of these
regulations in the Official Gazette. Provided that prior to submitting the detailed procedure to the
Commission for approval, the Central Transmission Utility shall make the same available to the
public and invite comments by putting the draft detailed procedure on its website and giving a
Page | 61
period of one month to submit comments; Provided further that while submitting the detailed
procedure to the Commission, the Central Transmission Utility shall submit a statement
indicating as to which of the comments of stakeholders have not been accepted by it along with
reasons thereof. The detailed procedure submitted by the Central Transmission Utility shall, in
particular, include—
a)The proforma for the connection agreement.
b)The proforma for the long-term access.
Provided that the Transmission Service Agreement issued by the Central Government as part of
standard bid documents for competitive bidding for transmission in accordance with section 63
of the Act shall be a part of this Agreement along with necessary changes; Provided further that
in case transmission system augmentation is undertaken through the process of competitive
bidding in accordance with section 63 of the Act, the Transmission Service Agreement enclosed
as part of bid documents shall be used as a part of the proforma agreement to be entered into
between the applicant and the Central Transmission Utility for long-term access. The time line
for phasing of construction/modification of the transmission elements by the Central
Transmission Utility/transmission licensee, as the case may be, and the coming up of generation
facilities or facilities of bulk consumer, as the case may be, so as to match the completion times
of the two; Provided that the time period for construction of the transmission elements shall be
consistent with the timeline for completion of projects. Aspects such as payment security
mechanism and bank guarantee during the period of construction and operation: Provided that
the bank guarantee during construction phase shall not exceed Rs. 5 lakh per MW of the total
power to be transmitted by that applicant through inter-State transmission system. Provisions for
collection of the transmission charges for inter- State transmission system from the long-term
customers or medium-term customers, as the case may be, by the transmission licensee or the
Central Transmission Utility.
Page | 62
Figure 24: Transfer of Electricity Region Wise Through Medium Term Open
Access
Power transfer in MW
3000
2500
2000
1500
1000
500
0
Power transfer in MW
Short Term Open Access
Short-term transactions of electricity refers to contracts of less than one year period, for
electricity transacted under bilateral transactions through Inter-State Trading Licensees (only
inter-state part) and directly by the Distribution Licensees, Power Exchanges (Indian Energy
Exchange Ltd (IEX) and Power Exchange India Ltd (PXIL)), and Unscheduled Interchange (UI).
The analysis includes
i.
Years/Monthly/Daily trends in short-term transactions of electricity
ii.
Analysis of open access consumers on power exchanges;
iii.
Major Sellers and Buyers of Electricity through Licensed Traders and Power
Exchanges
iv.
Effect of congestion on Volume of Electricity transacted through Power
Exchanges Comparison of short-term prices with tariffs of long-term sources
of power for various distribution companies.
Page | 63
I: Volume of Short-term Transactions of Electricity
During the month of April 2013, total electricity generation excluding generation from
renewable and captive power plants in India was 77557.10 MUs .Of the total electricity
generation, 7605.62 MUs (9.81%) were transacted through short-term, comprising of 3448.80
MUs (4.45%) through Bilateral (through traders and term ahead contracts on Power Exchanges
and directly between distribution companies), followed by 2576.54 MUs (3.32%) through day
ahead collective transactions on Power Exchanges (IEX and PXIL) and 1580.28 MUs (2.04%)
through UI .Of the total short-term transactions, Bilateral constitute 45.35% (35.46% through
traders and term-ahead contracts on Power Exchanges and 9.89% directly between distribution
companies) followed by 33.88% through day ahead collective transactions on Power Exchanges
and 20.78% through UI .
The percentage share of electricity traded by each trading licensee in the total volume of
electricity traded by all trading licensees is provided . The trading licensees undertake electricity
transactions through bilateral and through power exchanges.
Here, the volume of electricity transacted by the trading licensees includes bilateral transactions
and the transactions undertaken through power exchanges. There were 42 trading licensees as on
30.04.2013, of which only 21 have engaged in trading during April 2013. Top 5 trading licensees
had a share of 68.91% in the total volume traded by all the licensees.
Herfindahl-Hirschman Index (HHI) has been used for measuring the competition among the
trading licensees. Increase in the HHI generally indicates a decrease in competition and an
increase of market power, whereas decrease indicates the opposite. The HHI below 0.15
indicates non-concentration of market power. The HHI computed for volume of electricity traded
by trading licensees (inter-state & intra-state) was 0.1174 for the month of April 2013, which
indicates that there was no concentration of market power.
The volume of electricity transacted through IEX and PXIL in the day ahead market was 2515.68
MUs and 60.86 MUs respectively. The volume of total Buy bids and Sale bids was 3958.66 MUs
Page | 64
and 3663.90 MUs respectively in IEX and 250.63 MUs and 162.49 MUs in PXIL. The gap
between the volume of buy bids and sale bids placed through
power exchanges shows that there was more demand in IEX (1.08 times) and PXIL (1.54times)
when compared with the supply offered through these exchanges.
The volume of electricity transacted through IEX and PXIL in the term-ahead market was 7.48
MUs and 19.71 MUs respectively .
II: Price of Short-term Transactions of Electricity
(i) Price of electricity transacted through Traders:
Weighted average sale price has been computed for the electricity transacted through traders and
it was `4.55/kWh. Weighted average sale price was also computed for the transactions during
Round the Clock (RTC),
Peak, and Off-Peak periods separately, and the sale prices were `4.60/kWh, `4.63/kWh and
`4.12/kWh respectively. Minimum and Maximum sale prices were `2.90/kWh and `8.04/kWh
respectively .
(ii) Price of electricity transacted Through Power Exchanges: Minimum, Maximum and
Weighted Average Prices have been computed for the electricity transacted through IEX and
PXIL separately. The Minimum, Maximum and Weighted Average prices were `1.31/kWh,
`19.60/kWh and `3.74/kWh respectively in IEX and `1.31/kWh, `5.00/kWh and `2.71/kWh
respectively in PXIL .
The price of electricity transacted through IEX and PXIL in the term-ahead market was
`3.14/kWh and `3.38/kWh respectively.
(iii) Price of electricity transacted Through UI: All-India UI price has been computed for
NEW Grid and SR Grid separately. The average UI price was `2.27/kWh in the NEW Grid and
`4.29/kWh in the SR Grid. Minimum and Maximum UI prices were `0.00/kWh and `10.80/kWh
respectively in the New Grid, and `0.00/kWh and `10.80/kWh
respectively in the SR Grid .
Page | 65
III: Volume of Short-term Transactions of Electricity (Regional Entity1-Wise)
Of the total bilateral transactions, top 5 regional entities sold 48.87% of the volume, and these
were Sterlite, Karnataka, Damodar Valley Corporation, Jindal Power Limited and UT
Chandigarh. Top 5 regional entities purchased 58.49% of the volume, and these were West
Bengal, Tamilnadu, Gujarat, Andhra Pradesh and Kerala .
Of the total Power Exchange transactions, top 5 regional entities sold 63.39% of the volume, and
these were Gujarat, Karnataka, Delhi, Madhya Pradesh and Haryana. Top 5 regional entities
purchased 66.64% of the volume, and these were Gujarat, Maharashtra, Andhra Pradesh, Punjab
and Rajasthan .
Of the total UI transactions, top 5 regional entities underdrew 38.59% of the volume, and these
were Uttar Pradesh, Rajasthan, Madhya Pradesh, Maharashtra and Delhi. Top 5 regional entities
overdrew 37.25% of the volume, and these were Chattisgarh, Maharashtra, Uttar Pradesh,
Haryana and Gujarat . Regional entity-wise total volume of net short-term transactions of
electricity i.e. volume of net transactions through bilateral, power exchanges and UI .
Top 5 electricity selling regional entities were Karnataka, Sterlite Energy Limited, Delhi, Jindal
Power Limited and Damodar Valley Corporation.
Top 5 electricity purchasing regional entities were Tamilnadu, Andhra Pradesh, West Bengal,
Maharashtra and Chattisgarh.
IV: Congestion2 on Inter-state Transmission Corridor for Day-Ahead Market on Power
Exchanges
Power Exchanges use a price discovery mechanism in which the aggregate demand and supply
are matched to arrive at an unconstrained market price and volume. This step assumes that there
is no congestion in the inter-state transmission system between different regions. However, in
reality, the system operator, NLDC in coordination with RLDCs, limits the flow due to
congestion in the inter-state transmission system. In such a situation, Power Exchanges adopt a
mechanism called ―Market Splitting‖3.
In the month of April 2013, congestion occurred in both the power exchanges, the
Page | 66
details of which are shown in Table-16. The volume of electricity that could not be cleared
due to congestion and could not be transacted through power exchanges is the difference
between unconstrained cleared volume (volume of electricity that would have been
scheduled, had there been no congestion) and actual cleared volume.
During the month, the volume of electricity that could not be cleared in the power
exchanges due to congestion was 17.17% and 56.37% of the unconstrained cleared volume
in IEX and PXIL, respectively. In terms of time, congestion occurred was 100.00% in both
the power exchanges.
Page | 67
FIGURE 25: SHORT TERM TRANSACTION OF ELECTRICITY FOR THE YEAR
2012-13 IN QUARTERLY BASIS
STERLITE
Gujarat
MP
Rajasthan
Maharashtra
Haryana
Punjab
1500.00
1000.00
500.00
0.00
-500.00
Uttar Pradesh
First quarter (2012-13)
First quarter (MUs)
 In the above table it is clearly visuable that Uttar Pradesh and punjab are the top most
electricity buyer and Sterlite and jindal power are the top most electricity seller.
 Uttar Pradesh is the top buyer in first quarter ,the reason behind this is it is a time of
starting of summer and UP has more population comparatively other.
Second quarter (2012-13)
2000.00
1500.00
1000.00
500.00
0.00
-500.00
-1000.00
Second quarter (MUs)
 In the second quarter Punjab is the top most buyer having more than 1600 MUs .
Page | 68
 The main reason behind this is that it a time of
summer peak demand and also
agriculture time.
 Punjab used heavly electricity in agriculture sector.
 UP has almost same demand as first quarter.
 Now in the second quarter MP has come into the top seller of electricity in the short term
basis.
 MP has increased its sells 199% in second quarter as compared to first quarter.
Third quarter (2012-13)
1000.00
500.00
0.00
Delhi
Karnataka
JINDAL POWER
DVC
Gujarat
Kerala
MP
Rajasthan
Maharashtra
-1000.00
Andhra Pradesh
-500.00
Third quarter (MUs)
 Now in the third quarter AP is top most buyer .
 MP become the buyer in third quarter instead of seller in first and second quarter.
 Delhi is the top seller of electricity in the third quarter.
Page | 69
Fourth quarter (2012-13)
600.00
400.00
200.00
-1000.00
Delhi
Karnataka
STERLITE
DVC
MP
JINDAL POWER
-800.00
Rajasthan
-600.00
Kerala
-400.00
Tamilnadu
-200.00
Andhra Pradesh
0.00
Fourth quarter (MUs)
 Delhi remain in top seller of electricity
UNSCHEDULED INTERCHANGE
FIGURE :26 Volume of export through UI charges of five states
2500
2000
1500
1000
total vol (MU) export in
2011-12
500
0
total vol (MU) export In
2012-13

UI charges has reduced in year 2012-13 as compared to year 2011-12
FIGURE :27 Volume of Import through UI charges of five states
Page | 70
4000
3715.24
3164.82
2000
total vol (MU) import in 201112
2724.67
3000
1849.58
1351.42
962.35
1878.95
1152.78 1079.7
643.38
1000
0
 Punjab and Uttar Pradesh has increased the overdrawal electricity in UI charges in year
2012-13 as compared to 2011-12.
CORRIDOR ANALYSIS
Introduction:
The corridor analysis is very important for generating companies to sell power in Short term
power market. The corridor analysis give clear view about the total transfer capability
(TTC),availability transfer capability (ATC) for power evacuation for short term transaction and
transmission reliability margin (TRM). ‗Transfer Capability‘ as the measure of the ability of
interconnected electric systems to reliably move power from one area to another over all
transmission lines (or paths) between those areas under specified system conditions. It is
directional in nature and is highly dependent upon the generation, customer demand and
transmission system conditions assumed during the time period analyzed.
Total Transfer Capability (TTC) : Total transfer capability is defined as the amount of electric
power that can be transferred over the interconnected transmission network in a reliable manner
while meeting all of a specific set of pre- and post-contingency system conditions.
Difference between transfer capability and transmission capacity:
Page | 71
Transfer Capability is different from ‗Transmission Capacity‘, which usually refers to the
thermal limit or rating of a particular transmission element or component.
The capability to meet load (transfer capability) would however depend on several other factors
such as spatial distribution and diversity of generation/load, network configuration (radial or
meshed), availability of reactive compensation within that control area.
Thus, the individual transmission line capacities or ratings cannot be arithmetically added to
determine the transfer capability of a transmission path or interface.
Available Transfer Capability (ATC):
Available Transfer Capability (ATC) is a measure of the transfer capability remaining in the
physical transmission network for further commercial activity over and above already committed
uses. It is derived from the Total Transfer Capability (TTC) after discounting the reliability
margins. Thus ATC = TTC- Reliability Margins.The reliability margins could be classified as
Transmission Reliability Margin (TRM) and Capacity Benefit Margin (CBM). These have been
explained in the subsequent sections.
Assessment of transfer capability
Due to the complexity involved, the assessment of transfer capability from one area to another in
an interconnected system is carried out with the help of computer simulation studies. These
studies are to be carried out for a particular scenario or snapshot, which is based on certain
assumptions and forecasts. The factors, inter alia that are to be considered in these simulations
are as below:
i. Planning criteria.
ii. Forecasted demand- peak/off peak/transitions/four cardinal points.
iii. Generation despatch based on maintenance schedule for thermal and forecasted hydro
generation during peak/off peak.
iv. System Configuration—new lines expected or existing lines under outage.
v. Base Schedule Transfers mainly intra regional transactions known in advance.
vi. Credible System contingencies.
Page | 72
Limits to Transfer Capability
The ability of interconnected transmission network to reliably transfer power may be limited by
the physical and electrical characteristics of the systems.
The limiting condition on some portions of the transmission network or flow gates can shift
among thermal, voltage and stability limits as the network operating conditions change over
time. TTC would be minimum of thermal limit, voltage Limit and stability Limit.
Reliability Margins
Calculations of future transfer capabilities must consider the inherent uncertainties in projecting
such system parameters over longer time periods. These include projections of system
conditions, transmission system topology, projected customer demand and its distribution,
generation despatch, location of future generators, future weather conditions, available
transmission facilities and existing and future power transactions.
Margins in the form of Transmission Reliability Margin (TRM) and Capacity Benefit Margin
(CBM) must be kept aside to provide operating flexibility in real time.
Transmission Reliability Margin (TRM)
Page | 73
NERC document on Transmission Capability Margins and their use in ATC determination
defines TRM as the amount of transmission transfer capability necessary to provide a reasonable
level of assurance that the interconnected transmission network will be secure. TRM accounts for
the inherent uncertainty in system conditions and its associated effects on ATC calculations, and
the need for operating flexibility to ensure reliable system operation as system conditions
change.
Capacity Benefit Margin (CBM):
As per the 1996 NERC document, Capacity Benefit Margin (CBM) is defined as that amount
of transmission transfer capability reserved by load serving entities to ensure access to
generation from interconnected systems to meet generation reliability requirements. CBM is a
more locally applied margin than TRM, which is more of a network margin. The (n-1) criteria is
applied while evaluating the first contingency transfer capability. However a considerable
difference exists between what is a (n-1) contingency in planning horizon and a (n-1)
contingency in operating horizon.
- A tower collapse or ‗lightning strike‘ on a D/C tower would result in simultaneous loss of two
elements.
- Non-availability or outage or non-operation of bus bar protection at a substation would result
tripping of all the lines emanating from the substation at remote end in Zone-2.
- In a substation having breaker and a half switching scheme, outage of a combination of
breakers could result in tripping of multiple for a fault on one line.
- Tripping of both the poles of an HVDC bipole system.
Therefore all such practical considerations call for an even higher reliability margin with
consequent further reduction in ATC.
Page | 74
Consequences of not providing for a Reliability Margin in Indian context:
The consequences of scheduling the interregional links at the full TTC level without any margin
are as under:
1. Power shortages and compulsion to meet demand by most of the state utilities would
result in more load being connected in the Northern and Western grid. This would lead to
a drop in frequency, as there would not be commensurate increase in generation in
Eastern region. The line loadings would also increase above the TTC levels and make the
system insecure to even one element outage. A 1 Hz change in frequency could result in
inter regional line loading changes of the order of 1000 MW.
2. Tight control at the interregional level (no UI) would be completely inconsistent with loose
control at the inter state level (no limit on UI) and a floating frequency regime).
3. There would be frequent curtailments in real time, which would affect all the RLDCs/SLDCs
in the country. The effect on a single transaction due to curtailment could be as low as 2 MW
and the grid operators would be busy in rescheduling and catering to this ‗private‘ need of
stakeholders at a time when the larger ‗public‘ issue of grid security is at stake. It also has the
potential for creating disputes.
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4. Unlike a safety net in the form of Under Frequency Relays (UFRs) available for low
frequency, there is no safety net in the form of System Protection Schemes (SPS) to take care
of cascade trippings and Under Voltage Relays to guard against voltage collapse. Thus
reliability margins are absolutely essential and are non negotiable for providing a reliable
transmission services to all transmission system users under a broad range of potential
system conditions. These margins are reserved by grid operators and made available for use
by all the transmission users in real time.
Findings of Corridor Analysis:
The total transfer capability and available transfer capability between western region to
southern region is 1000MW but all the power transfer capability allotted to long term
access(LTA) and medium term open access (MTOA). There is no power transfer capability
available for short term open access (STOA).The reliability margin between western region
to southern region is zero.
The total transfer capability and available transfer capability between eastern region to
southern region is 830MW. 612MW power transfer capability allotted to long term
access(LTA) and medium term open access (MTOA). And 612MW of power transfer
capability available for short term open access (STOA). The reliability margin between
eastern region to southern region is zero.
The total transfer capability between northern region to western region is 2500MW and
available transfer capability2000 MW. 286MW power transfer capability allotted to long
term access(LTA) and medium term open access (MTOA). And 1714MW of power transfer
capability available for short term open access (STOA). The reliability margin between
northern region to western region is 500 MW.
The total transfer capability between northern regions to eastern region is 1100MW and
available transfer capability 900 MW. 0 MW power transfer capability allotted to long term
access(LTA) and medium term open access (MTOA). And 900 MW of power transfer
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capability available for short term open access (STOA). The reliability margin between
northern region to eastern region is 200 MW.
The total transfer capability between eastern region to north- eastern region is 590MW and
available transfer capability 555 MW. 230MW power transfer capability allotted to long
term access(LTA) and medium term open access (MTOA). And 325 MW of power transfer
capability available for short term open access (STOA). The reliability margin between
eastern region to north- eastern region is 35 MW.
The total transfer capability between WR to NR1 is 5700 MW and available transfer
capability 5200 MW. 2787MW power transfer capability allotted to long term access(LTA)
and medium term open access (MTOA). And 2413 MW of power transfer capability
available for short term open access (STOA). The reliability margin between WR to NR1 is
500 MW.
From corridor analysis found that there no reliable margin between western region to southern
region and eastern region to southern region. This shows the congestion of these network due
power deficit and huge demand in southern region. Also it shows that there is need for
development high capacity transmission corridor between ER and SR to transfer surplus
power from ER region to power deficit SR region.
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CONCLUSION
As Housing Infrastructure Development Finance Corporation (HDFC) chairman Mr. Deepak
Parekh said, ―India‘s power sector is a leaking bucket; the holes deliberately crafted by various
stakeholders that control the system. The logical thing to do would be to fix the bucket rather
than to persistently emphasise shortages of power and forever make exaggerated estimates of
future demand. Most initiatives in the power sector are nothing but ways of pouring more water
into the bucket so that consistency and quantity of leaks are assured.‘‘ This statement is reality
today, the current generation capacity of India reached 225133,11 MW and expected generation
addition for 2013-14 is 18,432 MW. The growth in generation capacity addition from 2012-13 to
2013-14 is 11.65%. Also the energy requirement of India is also increasing, the energy
requirement in the country is projected to grow at a CAGR of 7.5% during 12th plan period.
After the huge capacity addition in past few years there is huge deficit in different region of
India, as per CEA report except the eastern one would face an energy shortage. This would vary
from 1.2 per cent in the western region to 19.1 per cent in the southern one. Peaking shortages in
the northern, southern, and north-eastern regions would be 1.3, 26.1 and 10 per cent,
respectively. This huge deficit in southern and north-eastern region is due to the transmission
constraint between ER-SR and NER-SR region. Due to inter-regional transmission constraints
between the NEW Grid and SR Grid, the overall average anticipated peak shortage of the
NEW+SR Grid works out to 6.2 per cent.
As the eastern region has rich coal blocks the power developers invest to build large size
Thermal power plants in this region and also due to low demand the eastern region become
power surplus. But the bulk power from eastern region is not transfer efficiently to power deficit
other regions due to transmission constraint. This make the available resources under utilized.
About 2,000 Mw capacity of independent power projects likely to be commissioned during the
year 2013-14 is not yet linked with any entity. Also the it is hard for generating companies to sell
power to open access consumers in Intra state trading in states like Odisha. The cross subsidy
surcharges of some states are very high and also due to the intra state transmission constraint the
generating companies struggle to sell there power in medium term and short term basis on power
market. This reduce the Plant Load Factor (PLF) of the generating units and the asset and
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resources of generating units are under utilized. Also in exchange the clearing volume of power
is less as compare with buying and selling bid put by the seller and buyer. In Power Trading also
the price in southern is much higher than the price of power in new grid this encourages the
generating companies to sell power in southern region. But due to transmission constraint and
bad financial condition of state utilities power trading is not much effective.
The central government should take necessary steps to strengthen the transmission capacity
with help of public-private partnership in transmission sector. Also the state government and the
central government should put proper strategy to improve the financial condition of state
utilities. And also the state governments and central government put proper laws and frame work
to allow open access and encourage supplier and buyers to trade through medium term and short
term power market. This will encourage investor to invest in Indian Power Market and will help
to bring growth in Power Sector.
RECOMENDATION

The Government of India granted such a formal approval on 23.5.2007 to Vedanta
Aluminium Limited proposal for the development, operation and maintenance of sector
specific Special Economic Zone (SEZ) in Jharsuguda district in Orissa. Vednta
Aluminium Ltd develop it‘s 1.25MTPA aluminium plant expansion project and it‘s
subsidiary company Sterlite Energy has set up 4x600MW (2400MW) Independent
power plant (IPP). The Sterlite energy IPP is operational now. As per Section 49(1) of
SEZ Act,2005, the developer of Special Economic Zone was declared as a deemed
licensee for distribution of electricity within the Special Economic Zone area. Thus, the
status of deemed distribution licensee stands granted to the Appellant by virtue of the said
notification. As it has got the deemed distribution licensee to distribute power in SEZ
region. So Vedanta Aluminium Ltd can sign a long term Power Purchasing Agreement
(PPA) with Sterlite Energy Ltd to purchase power for it‘s new aluminium smelter plant.
This will benefit Vedanta Aluminium Ltd by purchasing power in low price by without
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paying cross subsidy charges, transmission charges and other surcharges to the
distribution company.

Sterlite Energy Ltd supply 600MW of power to Grid Corporation of Orissa through
Bilateral agreement and other 600MW through short term open access (STOA). It can
sell it‘s power in power trading market to different open access consumers in different
region of India to get maximum per unit price. The trading price in southern region is
highest compare to other region in the country, so they should try to sell more volume of
power to southern region for high gain for per unit power sold.

The Sterlite Energy Ltd can put it‘s power sell bid on the Indian Energy Exchange (IEX)
by analysing different transmission corridor, availability transfer capability (ATC) and
peak demand of different region . They can sell maximum volume of power in IEX
which will generate revenue for operation of plant and also for the organisation.

The Sterlite Energy Ltd can supply power to bulk power consumer through Open Access.
With permission from concern SLDC, transmission utility, state electricity board it can
supply to intrastate and interstate Open access consumer by paying transmission charges,
wheeling charges, transmission loss charges and other surcharges as per agreement. This
power sell through Open access to bulk consumer will generate revenue and also will
help to increase the Plant Load Factor (PLF).
.
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BIBLIOGRAPHY
 www.cea.nic.in
 www.cercind.gov.in
 www.powergridindia.com
 www.nldc.in
 www.nrpc.gov.in
 www.vedantaaluminium.com
 www.sldcorissa.org.in
 www.erldc.org
 www.srldc.org
 www.nrldc.org
 www.wrldc.org
 Electricity Act 2003
 National Tariff Policy
 www.iexindia.com
 www.ptcindia.com
 www.tatapowertrading.com
 www.nvvnl.co.in
 www.lancogroup.com
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